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Riazi, Eser, Agrawal, Peña Díez

Dr. M. R. Riazi is currently a Professor of Chemical Engineering at Kuwait University. He was previ-

Petroleum
ously an Assistant Professor at Pennsylvania State University (USA), where he also received his MS
and PhD. He was also a visiting professor at various universities in the U.S., Canada, Europe and
the Middle East. He has been consultant and invited speaker to more than 50 oil companies and
research institutions in Canada, the U.S., Europe, India, China, Malaysia, Australia, the Middle East
and North Africa, including invited speaker to the World Economic Forum. He is the author/co-author
of more than 100 publications, including three books mainly in the areas of petroleum and chemical
technology. He is the founding and Editor-in-Chief of IJOGC and an associate editor of some other

Refining and
international journals. He was awarded a Diploma of Honor from the National (American) Petroleum
M. R. Riazi
Engineering Society, as well as teaching and research awards from various universities. He is a
member of AIChE and the Research Society of North America. (www.RiaziM.com)

Semih Eser is a Professor of Energy and Geo-Environmental Engineering at Penn State University.
He received his B.S. and M.S. degrees in Chemical Engineering from Middle East Technical University
in Ankara, Turkey and his Ph.D. in Fuel Science from Penn State University. Professor Eser teaches

Natural Gas
courses on petroleum refining and energy engineering at John and Willie Department of Energy
and Mineral Engineering and directs the Carbon Materials Program at the EMS Energy Institute at
Penn State. He has served as Program Chair, Chair, and Councilor in the Fuel Chemistry Division of
the American Chemical Society and as member of the Advisory Committee of the American Carbon
Society.

Semih Eser
Dr. Suresh S. Agrawal is founder and president of Offsite Management Systems LLC

Processing
(www.globaloms.com) and has developed and installed innovative and technologically advanced

Petroleum Refining and Natural Gas Processing

automation software products, and integrated solutions for the automation of offsite operations of
Chemical, Oil and Gas (COG) Industries. Dr. Agrawal has 25+ years of experience at senior positions
with companies, including being Director of Refinery Offsite Operations at ABB Industrial Systems,
Inc., Houston, Texas. He worked earlier with reputable companies such as 3X Corporation and Exxon
Corporation in New Jersey. Dr. Agrawal has successfully managed many advanced offsite refinery
control projects in numerous countries. He has a doctorate degree (Ph.D.) in Chemical Engineering
from the Illinois Institute of Technology, Chicago, and a Bachelors Degree in Chemical Engineering
Suresh S. Agrawal from Indian Institute of Technology (I.I.T.), Mumbai, India. He has published more than 20 technical
papers in the area of refinery offsite automation.

José Luis Peña Díez is a consultant at the Technology Center at Repsol in Madrid, Spain. His profes-
sional activity includes more than twenty years of experience leading and participating in research
projects in upstream and downstream petroleum technologies.
Following his studies in chemical sciences at the Complutense University of Madrid, he collaborated
with universities and academic institutions to coordinate activities in the areas of chemical
engineering and special process simulation. He is currently a part-time associate professor in
chemical engineering at the Rey Juan Carlos University of Madrid.
Peña Díez is the author of forty technical articles and presentations at international conferences in
José Luis Peña Díez the fields of petroleum fluids characterization, process engineering and control, and process
simulation, areas in which his expertise contributed to this book.

www.astm.org M.R. Riazi, S. Eser, S.S. Agrawal, J.L. Peña Díez, editors
ISBN: 978-0-8031-7022-3
Stock #: MNL58

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Petroleum Refining and Natural Gas
Processing

M.R. Riazi, Semih Eser, Suresh S. Agrawal, and José Luis Peña Díez, Editors

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Library of Congress Cataloging-in-Publication Data

Petroleum refining and natural gas processing / M.R. Riazi ... [et al.].
p. cm. — ([ASTM manual series] ; MNL 58)
Includes bibliographical references and index.
ISBN 978-0-8031-7022-3 (alk. paper)
1. Petroleum—Refining. 2. Natural gas. I. Riazi, M. R.
TP690.P4728 2011
665.5’3—dc23 2011027593

Copyright © 2013 ASTM International, West Conshohocken, PA. All rights reserved. This material may not be reproduced
or copied, in whole or in part, in any printed, mechanical, electronic, film, or other distribution and storage media, without
the written consent of the publisher.

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Conshohocken, PA 19428-2959; Tel: 610-832-9634; online: http://www.astm.org/copyright/

ASTM International is not responsible, as a body, for the statements and opinions advanced in the publication. ASTM Inter-
national does not endorse any products represented in this publication.

Printed in
2013
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iii

Foreword
THIS PUBLICATION, Petroleum Refining and Natural Gas Processing, was sponsored by Committee D02 on Petroleum
Products and Lubricants. This is Manual 58 in ASTM International’s manual series.

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To
Our families

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Preface
Oil and gas have been the main sources of energy the world over for the past century and will remain important sources of
energy for the first half of this century, and possibly beyond. Currently, more than 60 % of the world’s energy is produced
from oil and gas, and energy needs are increasing. In addition, oil and gas provide the main feedstocks for the petrochemical
industry. World population is expected to increase to eight billion by 2030, which will demand an increase in energy of 40 %
in the next two decades. With these increases in energy consumption it is becoming necessary to consider unconventional
types of oils. Such oils, which are heavier, require more rigorous processing and treatment. The evolution of petroleum
refining began with the birth of modern oil production in Pennsylvania in the nineteenth century. Current refineries are
much more complex than those of a few decades ago and there is significant research concerning the development of more
economical uses of available hydrocarbon resources.
In the past few decades there has been an increase in the number of publications that report advancements in the
petroleum industry. Petroleum Refining and Natural Gas Processing is a continuation of those efforts and attempts to bring
together the most recent advances in various areas of petroleum downstream activities, with an emphasis on economic and
environmental considerations, heavy-oil processing, and new developments in oil and gas processing.
The primary goal of this book is to provide a comprehensive reference that covers the latest developments in all aspects
of petroleum and natural gas processing in the downstream sector of the petroleum industry. It includes topics on economy
and marketing, scheduling and planning, modeling and simulation, design and operation, inspection and maintenance, cor-
rosion, environment, safety, storage and transportation, quality and process control, products specifications, management,
biofuel processing and production, as well as other issues related to these topics. Every attempt has been made to avoid
overlap between chapters, however, there are some topics that have been included in more than one chapter when relevant
to both chapters. Another objective of this book is to describe the latest technology available to those working in the petro-
leum industry, especially designers, researchers, operators, managers, decision-makers, business people, and government
officials. The petroleum industry is a diverse and complex industry and it is almost impossible to include all aspects of it
in a single book. However, we tried to cover the most vital issues and we believe this is the most comprehensive resource
published to date for use by people involved in this worldwide industry. We hope this contribution will be useful to them. In
writing this book we benefited from the published works of many researchers, which are cited at the end of each chapter.
We welcome comments and suggestions from readers.
More than 40 scientists, experts, and professionals from both academia and industry have cooperated and contributed
to the 33 chapters in this book. Authors with years of experience made unique contributions not available in any similar
publications. We are grateful to all of them for their efforts in bringing this book to fruition.
We also thank the large number of anonymous reviewers who went through lengthy manuscripts and provided us with
their constructive comments and suggestions, which greatly enhanced the quality of the manual. Many publishers, organi-
zations, and companies provided us with permission to use their published data, graphs, and figures and we thank them
for their cooperation in supporting this publication effort.
We are also thankful to ASTM International for sponsoring publication of this book, especially to Kathy Dernoga,
Monica Siperko, Marsha Firman, and other ASTM staff involved in this project. Kathy Dernoga’s review and encouragement
were essential to the completion of this work. The support and encouragement of Dr. George E. Totten, ASTM’s Committee
on Publications representative for this manual, is also appreciated. The reviewing process was managed and conducted by
Christine Urso of the American Institute of Physics (AIP) and she was extremely cooperative in uploading the manuscripts
to the online reviewing site, inviting reviewers, and handling of all manuscripts submitted for this manual. Also, many
thanks to Rebecca L. Edwards, senior project manager at Cenveo Publisher Services for copyediting and production.
Finally, and most importantly, we thank our families for their patience, understanding, cooperation, and moral support,
which were essential throughout this process.

M. R. Riazi—Kuwait University, Kuwait

Semih Eser—The Pennsylvania State University, University Park, PA, USA
Suresh S. Agrawal—Offsite Management Systems, Houston, TX, USA
José Luis Peña Díez—Repsol, Madrid, Spain

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vii

Contents
Preface. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

Chapter 1—Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
M.R. Riazi, Semih Eser, José Luis Peña Díez, and Suresh S. Agrawal
Chapter 2—Feedstocks and Products of Crude Oil and Natural Gas Refineries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
M.R. Riazi and Semih Eser
Chapter 3—Worldwide Statistical Data on Proven Reserves, Production, and Refining
Capacities of Crude Oil and Natural Gas ��33
M.R. Riazi, Mohan S. Rana, and José Luis Peña Díez
Chapter 4—Properties, Specifications, and Quality of Crude Oil and Petroleum Products. . . . . . . . . . . . . . . . . . . . . . . 79
M.R. Riazi and Semih Eser
Chapter 5—Crude Oil Refining Processes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101
Semih Eser and M.R. Riazi
Chapter 6—Fluid Catalytic Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127
Ravi Kumar Voolapalli, Chiranjeevi Thota, D.T. Gokak, N.V. Choudary, and M.A. Siddiqui
Chapter 7—Hydroisomerization of Paraffins in Light Naphthas and Lube Oils for Quality Improvement . . . . . . . . . 159
B.L. Newalkar, N.V. Choudary, and M.A. Siddiqui
Chapter 8—Heavy-Oil Processing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 177
Semih Eser and Jose Guitian
Chapter 9—Advances in Petroleum Refining Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197
Isao Mochida, Ray Fletcher, Shigeto Hatanaka, Hiroshi Toshima, Jun Inomata,
Makato Inomata, Shinichi Inoue, Kazuo Matsuda, Shigeki Nagamatsu, and Shinichi Shimizu
Chapter 10—Advances in Catalysts for Refining Processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 223
Isao Mochida, Ray Fletcher, Shigeto Hatanaka, Hiroshi Toshima, Shikegi Nagamatsu,
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Makato Inomata, Rong He, Richard S. Threlkel, Christopher J. Dillon, Junko Ida,
Toshio Matsuhisa, Shinichi Inoue, Shinichi Shimizu, and Kazuo Shoji
Chapter 11—Natural Gas Conditioning and Processing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 249
Calogero Migliore
Chapter 12—Hydrogen Management. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 287
N. Zhang and F. Liu
Chapter 13—Design Aspects of Separation Units and Processing Equipment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 305
M.C. Rodwell and M.R. Riazi
Chapter 14—Process Control and Instrumentation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 355
L. Raman and N.S. Murthy
Chapter 15—Modern Computer Process Control Refining Units. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 375
Ravi Jaisinghani
Chapter 16—Refinery Inspection and Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 393
A.L. Kosta and Keshav Kishore
Chapter 17—Corrosion Inspection and Control in Refineries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 437
Jorge L. Hau
Chapter 18—Product Analysis and Quality Control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 455
Pradeep Kumar and N.S. Murthy

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viii Contents

Chapter 19—Fuel Blending Technology and Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 473

Suresh S. Agrawal
Chapter 20—Tank Farm Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 499
Suresh S. Agrawal
Chapter 21—Refinery Planning and Scheduling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 531
Nan Zhang and Marc Valleur
Chapter 22—Transportation of Crude Oil, Natural Gas, and Petroleum Products . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 549
Luis F. Ayala H.
Chapter 23—Introduction to Trading, Pricing, and Valuation of Crude Oils and Petroleum Products. . . . . . . . . . . . . 577
Cheng Seong Khor, Luis A. Ricardez-Sandoval, Ali Elkamel, and Nilay Shah
Chapter 24—A Review of Refinery Markets and Cost Estimation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 597
Mark J. Kaiser and James H. Gary
Chapter 25—Financial Risk Management in Refinery Operations Planning. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 631
Miguel Bagajewicz
Chapter 26—Process Modeling and Simulation of Refineries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 647
Maria J. Guerra, Pablo Jiménez-Asenjo, Antonio López-Rodríguez, and José L. Peña Díez
Chapter 27—Maintenance Simulation and Optimization in Refineries and Process Plants. . . . . . . . . . . . . . . . . . . . . . 675
Miguel Bagajewicz
Chapter 28—Roles of Computers in Petroleum Refineries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 685
Cheng Seong Khor and Ali Elkamel
Chapter 29—Environmental Issues Related to the Petroleum Refining Industry. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 701
Cheng Seong Khor and Ali Elkamel
Chapter 30—Safety Issues Related to Petroleum Refineries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 717
Joel M. Haight
Chapter 31—Refinery Management. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 729
Folkert J. Herlyn
Chapter 32—Biofuels and Biorefineries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 747
José Baro Calle
Chapter 33—Future Directions in Petroleum and Natural Gas Refining. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 769
Mohan S. Rana, Jorge Ancheyta, M.R. Riazi, and Meena Marafi
Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 801

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1
Introduction
M.R. Riazi1, Semih Eser2, José Luis Peña Díez3, and Suresh S. Agrawal4

Abbreviations and natural gas is a mixture of light hydrocarbons pro-

APC Advanced process control duced from petroleum and gas reservoirs.
API American Petroleum Institute There are several theories on the formation process of
DAO Deasphalted oil petroleum and hydrocarbons. It is generally believed that
DEG Diethylene glycol the petroleum is derived from aquatic plants and animals
EIA Energy Information Administration through conversion of organic compounds into hydrocar-
EPA U.S. Environmental Protection Agency bons. These organisms and plants under aquatic conditions
FCC Fluid catalytic cracking have converted inorganic compounds dissolved in water
FO Fuel oil (such as carbon dioxide) to organic compounds through the
GOR Gas-to-oil ratio energy provided by the sun,
GTL Gas-to-liquid
H-Oil Heavy oil 6CO2 + 6H 2O + energy → 6O2 + C 6 H12O6 (1.1)
HDS Hydrodesulfurization
LCO Light cycle oil
LPG Liquefied petroleum gas in which C6H12O6 (a carbohydrate) is an organic compound.
MDEA Monodiethanol amine Formed organic compounds may be decomposed into
MEA Monoethanol amine hydrocarbons under certain conditions of temperature and
NGL Natural gas liquid pressure,
OSHA Occupational Safety and Health Administration
(CH 2 O)n → xCO2 + yCH z (1.2)
PSA Pressure sewing adsorption
RON Research octane number
TEG Triethylene glycol in which n, x, y and z are integer numbers and yCHz is the
ULSD Ultralow sulfur diesel closed formula for the produced hydrocarbon compound.
VGO Vacuum gas oil Conversion of such organic materials to hydrocarbons
VRDS Vacuum residue desulfurization occurs under heat (~210–250°F), pressure (~2500 psi), and
radioactive rays. Catalysts for such reactions are vanadium
1.1 Petroleum Fluids, Refinery (V) and nickel (Ni), and for this reason some of these met-
Feedstocks, and Products als are found in small quantities in petroleum fluids. A
Petroleum was first used in 1546 by the German mineralo- geologic time of approximately 1 million years is required
gist George Bauer and was reported as a naturally occurring for completion of such reactions. In some other theories it
flammable liquid found in rocks that contain various types is suggested that calcium carbonate (CaCO3), an inorganic
of hydrocarbons. Petroleum and natural gas play an impor- compound, can be converted to calcium carbide (CaC2),
tant role in providing energy and the production of petro- which reacts with water (H2O) to make acetylene (C2H2),
chemicals. The word “petroleum” comes from the Latin a hydrocarbon. Either way, an aquatic environment is
words of petra (rock) and oleum, which refers to a special required for the formation of petroleum and that could be
type of oil [1]. Petroleum is a complex mixture of hundreds a good reason why major oil reservoirs are located in the
of hydrocarbons comprising mainly paraffins, naphthenes, vicinity of seas and oceans, and major oil fields are found
and aromatics. The lightest hydrocarbon component of at the seabeds of the Gulf of Mexico or the Persian Gulf in
petroleum is methane, which is the main element of natural the Middle East.
gas, and the heaviest components include asphaltenes, with Hydrocarbons produced from organic materials gradu-
molecular weights higher than 1000 that are found in heavy ally migrate through porous rocks and form a petroleum
oils. These complex high-molecular-weight structures also reservoir when a nonporous or seal rock is found. A series
contain heteroatoms such as nitrogen (N) and sulfur (S). of reservoirs within a common rock form an oil field.
In addition, small quantities of hydrogen and some metals Hydrocarbons found in different fields and reservoirs vary
are present in most crude oils as will be discussed later. In depending on their source and the maturity of the forma-
today’s terminology, crude oil is referred to as the liquid tion process, and this leads to the production of different
type of petroleum that is processed in petroleum refineries, kinds of reservoir fluids. Figure 1.1 shows seven kinds of

1
Kuwait University, Kuwait
2
The Pennsylvania State University, University Park, PA, USA
3
Repsol, Madrid, Spain
4
Offsite Management Systems LLC, Sugar Land, TX, USA
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1
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2 Petroleum Refining and Natural Gas Processing

natural gas gascondensate light crude intermediate heavy oil tar sand oil shale
(NGL) crude
%

Figure 1.1—Various categories of natural gas and liquid and naturally occurring petroleum fluids and their approximate
hydrocarbon molecular weight distributions according to their carbon numbers [2,3].

reservoir fluids from natural gas to tar sand and oil shale. of dissolved light gases. Table 1.1 gives a typical composi-
Heavy oil refers to crudes having an API gravity of less than tion of a reservoir fluid and the produced crude oil and
20 (or specific gravity > 0.93), whereas extra heavy oils, tar gases. Gas produced by this method is called associated gas
sands, oil shale, and bitumen are considered extra-heavy oil to distinguish it from natural gas produced directly from a
(API gravity < 10 or specific gravity > 1). These heavy flu- gas reservoir. Produced crude oil is then transferred to an
ids usually do not flow naturally (except in hot reservoirs), export terminal or to a local refinery for processing. In the
need artificial heating or enhanced recovery technologies case of natural gas, water can be separated through the gly-
for their extraction, and are considered as unconventional col dehydration process, as discussed in Chapter 11.
oils. Further specifications of these types of petroleum flu- In addition to the above forms of naturally occurring
ids are given in Chapter 2. hydrocarbons, there are huge amounts of hydrates under
Reservoir fluids can also be characterized by their the sea and at the bottom of oceans. Hydrates are ice-like
gas-to-oil ratio (GOR) when they are brought to atmo- crystalline structures formed under high pressures and low
spheric conditions. Dry gases contain more than 90 % temperatures where light hydrocarbons (i.e., C1, C2, C3, or
methane, and upon production at the surface have a GOR C4) are surrounded by water molecules. When hydrates are
of 100,000 (scf/bbl) or more whereas oils with a GOR of moved outside of the thermodynamic stability conditions
less than 1000 (scf/bbl) contain less than 50 % methane and they decompose into water and hydrocarbons, releasing
the produced crude oil has an API gravity of less than 40. large amounts of natural gas. However, current technolo-
Separation of oil and gas and production of crude oil from gies do not allow their commercial exploitation, and there
a reservoir fluid occurs at the surface facilities under field is an intense work of research facing the challenge of mak-
processing [3]. The water content of reservoir fluid is sepa- ing them a usable source of energy.
rated through a gravity-type separator, and the pressure In general, the distribution of elements present in a
of a reservoir fluid at the wellhead is gradually reduced to typical crude oil vary within fairly narrow limits, and on
1 atm in two- or three-stage gas-liquid separators, as shown weight basis they are 83–87 % carbon, 10–14 % hydrogen,
in Figure 1.2 [4]. In this figure, the pressure of a reservoir 0.1–2 % nitrogen, 0.05–1.5 % oxygen, 0.05–6 % sulfur, and
fluid with a GOR of 853 scf/bbl is reduced from 164.5 to less than 0.1 % metals such as vanadium, nickel, and cop-
1.01 bar in three stages. The liquid produced from the last per [1]. The quality of crude oils is determined by their API
stage is called crude oil and contains small concentrations gravity and sulfur contents. A lower carbon-to-hydrogen

GAS I GAS II GAS III

Reservoir Stage III

Stage I Stage II
Fluid T=32.2 o C
T=37.8 o C T=35 oC
P=21.7 P=5.2 P=1.01
LIQUID I LIQUID II bar LIQUID III
T=118.3 o C bar bar
(Crude Oil)
P=164.5 bar

Figure 1.2—Schematic of a three-stage separator in a Middle East production field [4].

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Chapter 1 n Introduction 3

Table 1.1—Calculated Composition (in mol %) of Crude Product from a Three-Stage Separator [4]
No. Component Feed First-Stage Gas Second-Stage Gas Third-Stage Gas Third-Stage Liquid

1 N2 0.09 0.54 0.12 0.05 0.00

2 CO2 2.09 3.91 4.09 1.44 0.02

3 H2S 1.89 1.47 4.38 5.06 0.14

4 H2O 0.00 0.00 0.00 0.00 0.00

5 C1 29.18 64.10 32.12 5.68 0.03

6 C2 13.60 19.62 32.65 25.41 0.38

7 C3 9.20 7.41 18.24 35.47 3.05

8 nC4 4.30 1.48 4.56 13.92 4.38

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9 iC4 0.95 0.41 1.23 3.47 0.78

10 nC5 2.60 0.36 1.01 3.98 4.81

11 iC6 1.38 0.24 0.68 2.61 2.37

12 C6 4.32 0.27 0.61 2.22 9.01

13 C7+ 30.40 0.19 0.31 0.69 75.03

Specific gravity at 60°F 0.8105

Temperature, °F 245 105 100 90 90

Pressure, psia 2197 315 75 15 15

GOR, scf/bbl 853 580 156 117

ratio of crude indicates a better quality and a higher heat- be replaced after consumption, comprise mainly fossil
ing value. General characteristics of various oils are given fuels, such as oil, natural gas, and coal. Renewable forms
in Table 1.2 and some specifications of petroleum products of energy include biomass, solar, wind, hydro (water), and
and their boiling ranges are presented in Table 1.3 [5]. geothermal energy. In addition, nuclear energy, which is
Products from an Alaskan crude oil with their respective produced from the nuclear fission of uranium, is considered
boiling range, carbon number, and yields are presented nonrenewable because of the limited uranium resources,
in Figure 1.3. Product specifications related to the quality but a potential future nuclear fusion technology could make
of fuels are changing with time as demonstrated in Table it be considered as an inexhaustible resource. According to
1.4 [5]. Further information about the quality and proper- the Energy Information Administration (EIA) [6], world
ties of petroleum crude oils and products are discussed in energy consumption in 2007 was 38 % oil, 23 % gas, 26 %
Chapter 4. coal, 6 % nuclear, 6 % hydro, and 1 % other renewable forms
of energy. This indicates that oil and gas provide more than
1.2 Status of World Energy Supply and 60 % of the world energy supply. In addition, oil and gas are
Demand the main source of feedstocks for petrochemical plants that
Various forms of energy sources can be divided into two are eventually converted into many industrial chemicals and
groups of nonrenewable and renewable forms. Nonrenew- materials, such as polymers and plastics, dyes, synthetic
able forms of energy, which refer to resources that cannot fertilizers, insecticides, and pharmaceuticals.
The total proved oil reserves in 2007 amount to 1238
billion bbl, with the Middle East share of 61 %, North and
Table 1.2—Properties of Light, Heavy, and South America account for 15 %, Europe and Euro-Asia 12 %,
Extra-Heavy Crudes and Residue Africa approximately 10 %, and the Asia Pacific region 3 %
Classification Definition of the total proved reserves. The estimated oil reserves
in 2008 were 1342 billion bbl up by 8 % from the previ-
Extra light High API gravity, low S, N, and ous year’s estimate. This is mainly due to the inclusion of
negligible asphaltene and metals
Canada’s heavy-oil sand reserves in the 2008 estimate [7].
Light crude Medium-range API gravity, low S, N, In addition, there are huge unconventional oil resources
metals, and moderate asphaltene distributed in Canada, South America, Russia, and China,
where the production could be economically feasible if
Heavy crude Medium-range API gravity, high S, N,
high metals, and asphaltene the oil price maintains above $80/bbl. With the addition
of unconventional oil reserves, the total world oil reserves
Extra heavy/residue Low API gravity and very high could reach approximately 10 trillion bbl. As of January 1,
contaminants (S, N, metals, and 2009, the proved world natural gas reserves were estimated
asphaltenes)
at 6254 trillion ft3, of which 40 % are located in the Middle
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4 Petroleum Refining and Natural Gas Processing

Table 1.3—Main Products Obtained during the Refining Processes along with Their Boiling
Point and Their Final Product Use [5]
Refinery Streams Boiling Range, °C Number of Carbons Processing Final Product(s)

LPG –40 to 0 1–4 Sweetener Propane fuel (bottled gas)

Light naphtha 39–85 ~8 Hydrotreater Gasoline (fuel for cars)

Heavy naphtha 85–200 ~10 Catalytic reformer Gasoline, aromatics (chemicals and plastics)

Kerosine 170–270 ~15 Hydrotreater Jet fuel, no. 1 diesel (fuel for aeroplanes)

Gas oil 180–343 ~20 Hydrotreater Heating oil, no. 2 diesel (fuel for car and
transportation)

Atmospheric residue 343+ Hydrotreater Fuel oil

Vacuum gas oil 340–566 ~35 FCC Gasoline, LCO, gases

hydrotreater fuel oil, FCC feed
lubricating plant lubricating basestock
hydrocracker gasoline, jet, diesel, FCC feed, lubricating
basestock

Vacuum residue 540+ 40+ Coker Coke, coker gas oil

visbreaker asphalt visbreaker gas oil, resid
unit deasphalted oil, asphalt
hydrotreater FCC feed
road surfacing

Vacuum
50
Residue - 655

Vacuum
40 Gas Oil
Boiling Point, oC
Carbon Number

- 455
30
Heavy
Atmospheric Distillation 46.9 % Gas Oil

- 345
20 Light
Gas
- 205
Kerosene

10
Naphtha

Vacuum Distillation 53.1 %

- -90
0
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

0 20 40 60 80 100
Volume Percent

Light Light Gasoline

Figure 1.3—Products of atmospheric distillation oil for a typical Alaskan crude oil [4].
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Chapter 1 n Introduction 5

and specialty gas (shale gas) is also starting to play an

Table 1.4—Finished Product Specifications important role in changing energy markets. On the other
and Future Worldwide Restrictionsa side, the progressive implementation of laws with focus
Foreseeable on carbon policies and energy efficiency may result in sig-
Situation in Situation in Trend nificantly different future consumption scenarios. Further
Fuel/Properties 1990s 2010 2010–2020 discussion on oil and natural gas reserves and the projec-
Gasoline tions of energy supply and consumption are presented in
Chapter 3.
Clear RON 89–94 95–98 98 Coal is another important fossil fuel in addition to oil
Clear MON 80–84 85–88 92 and gas and provides a significant share of the total energy
used in the world. A current status of coal production and
Benzene, vol % 3–5 1–2 <0.5 consumption in the world is presented in Figure 1.4. The
Aromatics, vol % 30–50 20–30 <30 estimated production peaks for oil, gas, and coal in the world
are shown in Figure 1.5 [8]. Various estimates indicate that
Olefins, vol % 10–20 5–10 <10
the world oil peak would occur sometime between 2015 and
Sulfur, ppm 300–500 50–100 <10 2020. It would be followed by peak gas and then peak coal.
The United States and China are the major producers of
Diesel oil
coal in the world, and China consumes more than twice the
Sulfur, ppm 2000–5000 50 <10 amount that the United States does because more than 83 %
of China’s electricity is produced by coal-burning power
Cetane number 45–50 50–53 >52
plants. Coal can also be converted into gaseous or liquid fuels

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Aromatics, vol % 25–35 10–20 <10 through gasification and (direct or indirect) liquefaction pro-
Fuel oil (LS FO) cesses, although coal liquids produced by direct liquefaction
have lower heating values than those of conventional oils
Sulfur, wt % 3–4 0.5–1 <0.5 and tend to contain more sulfur and other heteroatoms than
Nitrogen, wt % 0.5–0.7 0.3–.0.5 found in oil. Because coal has a higher carbon-to-hydrogen
ratio than that of oil, burning or conversion of coal produces
On average based on European standards from several studies [5].
a
large quantities of carbon dioxide that need to be mitigated
because of the global warming problem.
The contribution of different sources to the energy
East [6]. The production of natural gas in the world in 2006 production in recent years as presented above is expected
reached 104 trillion ft3, and it is projected to increase to 153 to change during this century. By the end of the 21st cen-
trillion ft3 in 2030 [7]. tury, the contribution of alternative sources of energy such
There is a general confidence that is based on exist- as solar, wind, or nuclear energy could exceed that of oil
ing reserves data on hydrocarbon availability for the next and gas. According to the U.S. Department of Energy,
decades, although the lower quality of the fluids and the the supply for oil will begin to decrease by 2020, and the
exploitation of more difficult reservoirs will have an effect demand for natural gas will peak around 2050. These pro-
on market price. The development of unconventional oil jections are obviously speculative and vary substantially

Asia & Oceania

North America
Geographical Regions

Coal Overview 2008

Europe
Imports
Exports
Eurasia
Consumption
Africa Production
0 10,000 20,000
Central & South America
Middle
East
Middle East

0 1,000,000 2,000,000 3,000,000 4,000,000 5,000,000

Thousands Short Tons

Figure 1.4—An overview of coal as a function of geographical region (2008).
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6 Petroleum Refining and Natural Gas Processing

Figure 1.5—Occurrence of peak oil, gas, and coal [8].

from one source to another. However, as the production fuel, diesel fuel, fuel oil, and non-fuel products such as
of energy from conventional and nonrenewable sources lubricating oils. Table 1.3 lists the main products obtained
decreases, there will be more attempts to produce energy during the refining processes along with their boiling point
from unconventional oil and gas and renewable energy ranges and final use. An overview of refinery processes as
sources such as biomass and solar energy, as discussed in well as feedstocks and products is given in Table 1.5 [9].
Chapter 3. Worldwide petroleum refineries and natural gas Applications and specifications of all fuels and materials
processing plant distribution as well as statistical data on obtained from crude oil refining are discussed in Chapters
refining capacities and expansion trends are also discussed 2 and 4.
in Chapter 3. One of the main characteristics of today’s modern
refineries is the capability to convert heavy crude oil
1.3 Petroleum Refining into light and middle distillates without producing heavy
Refining is a series of physical and chemical processes in residues. In today’s refineries, more than 44 % of a typical
which petroleum is converted into several products for crude oil can be converted into gasoline with less than 9 %
direct use or to provide feedstocks for petrochemical indus- ending up as heavy residues and carbon, compared with a
tries. Petroleum was first distilled by M.Z. Razi, a Persian gasoline yield of only 3 % from a simple batch distillation
chemist, who produced kerosine in the 9th century for use in the 19th century. A brief history of the refinery evolution
in kerosine lamps and for paving the streets of Baghdad is given in Table 1.6. This advancement of petroleum refin-
with tar. ing is due to the development of many new processes for
The first process of petroleum refining is desalting, in refining and upgrading the conventional and heavy oils, as
which the salt content of oil is reduced to 1–10 PTB (pound discussed in Chapters 5–10.
equivalent NaCl per thousand barrel of crude). Desalted oil Chapter 5 gives an overview of the objectives of petro-
then enters a distillation unit that operates at atmospheric leum refining, overall refinery flow, and the major processes
pressure. In this unit, crude oil is separated according to used for refining crude oil are divided into four categories:
boiling point range into distillate fractions such as lique- separation, conversion, finishing, and supporting pro-
fied petroleum gas (LPG), naphtha, kerosine, and light- and cesses. Separation processes make use of the differences in
heavy-gas oils. Figure 1.3 shows the distribution of distilla- the physical properties of crude oil components to separate
tion fractions for a typical Alaskan crude oil along with the groups of hydrocarbon compounds or inorganic impurities,
boiling point and carbon number ranges for the constituent whereas conversion processes cause chemical changes in
hydrocarbons. Atmospheric residue (composing 54 % of a the hydrocarbon composition of crude oils. Finishing pro-
typical Alaskan crude as seen Figure 1.3) is further frac- cesses involve hydrotreating to remove heteroatoms (S, N,
tionated in a vacuum distillation unit (at 40–50 mmHg) to and metals) and product blending to produce fuels and
produce vacuum gas oils and vacuum residue. Straight-run materials with desired specifications and in compliance
products from atmospheric distillation generally undergo with environmental and government regulations. Finally,
only finishing processes such as hydrotreatment to remove supporting processes provide the recovery of the removed
heteroatoms (e.g., S and N) and blending to achieve the heteroatoms or hetoroatom compounds, production of the
mandated specification before they are sold as final prod- hydrogen necessary for conversion and hydrotreating pro-
ucts. Vacuum distillation generates intermediate streams cesses, and effluent water treatment systems.
(i.e., vacuum gas oils and vacuum residue) that go through One of the main processes used in petroleum refiner-
a series of conversion and finishing processes to produce ies to crack heavy oils and residues into light- and middle-
light- and middle-distillate fuels, such as gasoline, jet distillate products is fluid catalytic cracking (FCC). FCC is a
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Chapter 1 n Introduction 7

Table 1.5—An Overview of Refining Processes and Their Feedstock and Valuable Products [9]
Process Name Reactions (Type) Feedstock(s) Product(s)

Fractionation processes

Atmospheric distillation Separation (thermal) Desalted crude oil Gas, gas oil, distillate, residual

Vacuum distillation Separation (thermal) Atmospheric tower residual Gas oil, lubricating stock, residual

Conversion processes-decomposition

Catalytic cracking Alteration (catalytic) Gas oil, coke distillate Gasoline, petrochemical feedstock

Coking Polymerize (thermal) Gas oil, coke distillate Gasoline, petrochemical feedstock

Hydrocracking Hydrogenate (catalytic) Gas oil, cracked oil, residual Lighter, higher quality products

Hydrogen steam reforming Decompose (thermal/catalytic) Desulfurized gas, O2, steam Hydrogen, CO, CO2

Steam cracking Decompose (thermal) Atmospheric tower heavy Cracked naphtha, coke, residual
fuel/distillate

Visbreaking Decompose (thermal) Atmospheric tower residual Distillate, tar

Conversion processes-unification

Alkylation Combining (catalytic) Tower isobutane/ cracker Isooctane (alkylate)

olefin

Polymerizing Polymerize (catalytic) Cracker olefins High-octane naphtha,

petrochemical stocks

Conversion processes-alteration or rearrangement

Catalytic reforming Alteration/dehydration Coker/hydrocracker naphtha High octane reformate/aromatic

(catalytic)

Isomerization Rearrange (catalytic) Butane, pentane, hexane Isobutane/pentane/hexane

Treatment processes

Amine treating Treatment (absorption) Sour gas, hydrocarbons with Acid free gases and liquid
CO2 and H2S hydrocarbons

Desalting Dehydration (absorption) Crude oil Desalted crude oil

Drying and sweetening Treatment (absorption/ Liquid hydrocarbons, LPG, Sweet and dry hydrocarbons
thermal) alkyl feedstock

Furfural extraction Solvent extraction (absorption) Cycle oils and lubricating High-quality diesel and lubricating
feedstocks oil

Hydrodesulfurization Treatment (catalytic) High-sulfur residual/gas oil Desulfurized olefins

Hydrotreating Hydrogenation (catalytic) Residuals, cracked Cracker feed, distillate, lubricating

hydrocarbons

Phenol extraction Solvent (extraction absorption/ Lubricating oil base stocks High-quality lubricating oils
thermal)

Solvent deasphalting Treatment (separation) Vacuum tower residual Propane heavy lubricating oil,
asphalt

Solvent dewaxing Treatment (cool/ filter) Vacuum tower lubricating oils Dewaxed lubricating basestock

Solvent extraction Solvent (extraction absorption/ Gas oil, reformate, distillate High-octane gasoline
precipitation)

Sweetening Treatment (catalytic) Untreated distillate/gasoline High-quality distillate/gasoline

major secondary processing unit in the petroleum industry perspective because it is a net volume generation process. It
for converting gas oil streams into high-octane gasoline, has gained a special place in the refinery because of its feed
cycle oils, LPG, and light olefins. After the carbon rejec- flexibility, ability to produce diverse products, and its quick
tion route, it upgrades low-value streams (e.g., vacuum response to the market demands through minor changes
gas oil, atmospheric residue, deasphalted heavy oils, etc.) in process operating conditions. The economics of the FCC
into distillates operating at low pressures and moderate process are so attractive that it is almost impossible to
temperatures. FCC is very attractive from a value addition imagine a modern refinery without this unit. Considering
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8 Petroleum Refining and Natural Gas Processing

Table 1.6—History of Petroleum Refining Processes

Year Process Name Purpose Byproducts, etc.

1849 Canadian geologist Abraham Gesner distills kerosine from crude oil

1859 An oil refinery is built in Baku (Azerbaijan)

1860–1861 Oil refineries are built near Oil Creek, Pennsylvania; Petrolia, Ontario, Canada; and Union County, Arkansas

1862 Atmospheric distillation Produce kerosine Naphtha, tar, etc.

1870 Vacuum distillation Lubricants (original) cracking feedstocks Asphalt, residual coker feedstocks
(1930s)

1913 Thermal cracking Increase gasoline Residual, bunker fuel

1916 Sweetening Reduce sulfur and odor Sulfur

1930 Thermal reforming Improve octane number Residual

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

1932 Hydrogenation Remove sulfur Sulfur

1932 Coking Produce gasoline basestocks Coke

1933 Solvent extraction Improve lubricant viscosity index Aromatics

1935 Solvent dewaxing Improve pour point Waxes

1935 Catalyst polymerization Improve gasoline yield and octane Petrochemical feedstocks
number

1937 Catalytic cracking Higher octane gasoline Petrochemical feedstocks

1939 Visbreaking Reduce viscosity Increased distillate, tar

1940 Alkylation Increase gasoline octane and yield High-octane aviation gasoline

1940 Isomerization Produce alkylation feedstock Naphtha

1942 Fluid catalytic cracking Increase gasoline yield and octane Petrochemical feedstocks

1950 Deasphalting Increase cracking feedstock Asphalt

1952 Catalytic reforming Convert low-quality naphtha Aromatics

1954 Hydrodesulfurization Remove sulfur Sulfur

1956 Inhibitor sweetening Remove mercaptan Disulfides

1957 Catalytic isomerization Convert to molecules with high octane Alkylation feedstocks
number

1960 Hydrocracking Improve quality and reduce sulfur Alkylation feedstocks

1974 Catalytic dewaxing Improve pour point Wax

1975 Residual hydrocracking Increase gasoline yield from residual Heavy residuals

1975 Catalytic converter The phaseout of tetraethyl lead begins Cleaner air

1990s SCANfining (Exxon), OCTGAIN (Mobil), Reformulated gasoline and low-sulfur Low sulfur fuel
Prime G (Axens), and S Zorb (Phillips) diesel

2000 Deep or ultra-deep desulfurization Decrease sulfur level in diesel (2 ppm) Sulfur
(ULSD)

the central role of FCC in refineries to produce better qual- reviews the processes and catalysts used for isomerization
ity fuels in higher yields, a separate chapter, Chapter 6, is of light naphtha and lubricating oils for quality enhance-
specifically devoted to a detailed discussion of the FCC ment. Isomerization of light naphtha, particularly C5 and
process. In addition to high-octane gasoline as the principal C6 paraffins, is practiced to achieve the desired research
product, FCC produces LPG as well as isobutane and olefin- octane number (RON) for gasoline blend stock in view of
rich light hydrocarbons (propene and butenes) that can be the stringent fuel specifications implemented worldwide.
used in alkylation and polymerization processes to produce Although the isomerization of C5/C6 paraffins has been
more high-octane gasoline in refineries. In addition to the known for a long while, only in recent years have commer-
alkylation and polymerization processes, the isomerization cial catalysts been developed for the isomerization of par-
process has also gained importance upon the recent limita- affins in the lubricating oil range. Over the years, catalyst
tions placed on the aromatic content of gasoline. Chapter 7 and process have evolved and improved. Thus, the scope of
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Chapter 1 n Introduction 9

Chapter 7 is to understand the chemistry and development roduce ultralow sulfur diesel (ULSD) and other low-sulfur
p
of hydroisomerization catalysts and the evolution of hydroi- fuels. Further discussion on future refineries is given in
somerization processes based on these developments, and it Chapter 33.
brings out future challenges and opportunities. Recent advances in the area of refining processes are
With the prospects of declining conventional crude presented in Chapter 9, whereas Chapter 10 is devoted to
oil reserves and large reserves of heavy crudes scattered the advancements in catalysts used in the refining pro-
around the world, there is increasing interest in efficient cesses. Catalysts play a critically important role in refin-
processing of heavy oils defined with respect to API grav- ing and natural gas processing, and the selection of an
ity, viscosity, and mobility at the field conditions. Because appropriate catalyst can improve the selectivity and quality
of these properties and the complexity of their chemical of product and help achieve higher conversion rates into
constitution, heavy oils present challenges for analysis and desirable products. Catalysts are expensive and constitute
upgrading into light distillates that have large demands. one of the major operating cost items incurred for running
Analysis and processing of heavy oils are discussed in full a refinery.
detail in Chapter 8. On the processing side, an integra-
tion of carbon rejection (solvent separation and thermal 1.4 Natural Gas Processing and
treatment), hydrogen addition (catalytic hydrogenation Hydrogen Management
and hydrocracking), and heteroatom removal (hydrotreat- The world production and consumption of natural gas is on
ing) offers a viable means of upgrading for transportation the rise, and a rough estimate indicates that current world
over long distances and conversion into light distillates. natural gas reserves could satisfy world energy demand
Chapter 8 provides an overview of current analytical tech- until the end of this century and even beyond, which is
niques and upgrading processes used to address the chal- what makes it be considered the world energy source for
lenges of bringing the heavy oils into the refineries and to the 21st century. Natural gas is the cleanest fossil fuel and
the market place. produces much less carbon dioxide (CO2) than coal or oil.
As shown in Figure 1.3, even conventional oil may pro- For example, for the production of 1 million Btu heat from
duce more than 50% residues from an atmospheric distilla- natural gas, oil, and coal, the total amounts of CO2 that
tion column. A flow diagram for upgrading a typical heavy are emitted into air are 117, 164, and 208 lb, respectively.
oil is shown in Figure 1.6. In general, refineries are moving However, the gas distribution chain is more complex than
in the direction of processing heavier oil, producing less other fuels and has delayed the worldwide implementation
coke and residues and producing more middle distillates compared with liquid fuels. It was not until the 1960s that
with the current economic and environmental constraints. the transport trials as liquefied natural gas (LNG) solved
A configuration suggested for future refineries is shown the existing limitations of natural gas as a local resource.
in Figure 1.7. One major goal of future refineries is to Because transportation is a major issue in the natural gas
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Gas
LPG

Gas
Distillates ( < 343 °C) Gas
FT-Synthesis
Primary Processes Secondary Process
Distillation

Hydrotreating
RDS
VRDS
+H2 HYVAL
Heavy or
Commercial Fuel (gasoline, diesel, jet fuel, heating
Catalytic

Extra Heavy OCR

oil, asphalt, lubricants, petrochemicals etc.)

Crude Oil Hydrocracking

H-Oil
LC-Fining Hydroprocessing
HYCON
ABC
Residue Fluid Cracking

Coking
Delayed coking
Non-catalytic

Fluid coking
Flexi-coking
+H2 Hydrovisbreaking
SDA DAO

Asphaltenes

Gasification Syngas

Figure 1.6—A flow diagram of typical oil refinery technologies for upgrading heavy crude oil and residue [10].
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10 Petroleum Refining and Natural Gas Processing

H 2 Plant H2
Sulfur Plant/Amines treatment Sulfur

Refinery
Gas
Fuel gases + LPG
FCC/ Ref.
Iso. nC 4 Dehydro . MTBE

Aromatics & High Octane

Iso. C 5-C6

Low Sulfur, Nitrogen,

Vapor FCC
Recovery MeOH
Alkylation Premium
Gasoline
Naphtha -HDS Catalytic Reforming
Crude
H2
Crude
Distillation
De-salting (Atm. Distillate -HDS
Pressure)

Low Sulfur, Nitrogen, Poly-

aromatics and High Cetane
Diesel/Jet Fuel
Gas Oil - HDS Catalytic Cracker Middle Distillate
Heating Oil
H2
Atm. Hydrocracker
Residue
Vacuum
Distillation VGO-HDS

Vacuum
Residue Deasphalting DOA ULSD Process
(10 ppm S)
Asphalt

Thermal
Processing
Industrial Fuel Oil

Figure 1.7—Possible petroleum refinery configuration of the future [5].

business, research on conversion of natural gas into liquid components as related to natural gas liquids (NGL) must be
fuels has been very intensive during the last decades try- removed from natural gas to meet specifications by using
ing to overcome this limitation, and it is another reason different technologies. Depending on local market needs,
to discuss natural gas processing in addition to petroleum NGL may be sold as a mixed product or sent to fraction-
refining in this book. ation processes to increase the market value of individual
The associated or free gas produced from a reservoir products as shown in Figure 1.9 [5]. Details on these pro-
goes through processes similar to crude oil at the field cesses as well as a review on natural gas liquefaction and
before it is sent to a gas processing plant. Commercial regasification technologies are given in Chapter 11, which
natural gas is primarily methane whereas raw natural gas also covers alternative natural gas conversion technologies
at the wellhead contains other compounds such as ethane, to liquid fuels [gas-to-liquid (GTL) technologies], which
propane, butane, and even heavier components as well as may become an economically viable option for large-scale
water, hydrogen sulfide (H2S), CO2, nitrogen, and some gas monetization projects. Figure 1.10 shows a schematic
other compounds. Purification processes for natural gas— of such processes [13].
conditioning and fractionation—are hence critical to meet Natural gas quality is mainly determined by its com-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

market specifications, and photographs of natural gas pro- position, particularly by its methane content. Natural gas
cessing and sweetening plants are shown in Figure 1.8 [11]. with higher methane content has better quality because
In field conditioning, acid gases and water are removed the ratio of hydrogen to carbon is higher in methane than
by various separation methods. Acid gases (CO2 and H2S) any other hydrocarbon compound. One of the main uses
are usually removed by chemical absorption with different of natural gas in petroleum and petrochemical plants is
amine technologies [monodiethanol amine (MDEA)-based to use it for the production of hydrogen through a steam
solvents are the most common] or by alternative processes reforming process as shown in Figure 1.11 [14–16 ]. Figure
such as physical absorption (Benfield, Sulfinol, Selexol) for 1.12 shows a hydrogen production plant in Europe with a
high-acid content gases. Membrane and molecular sieve capacity of 10,000 Nm3/h [17]. Hydrogen is used in petro-
adsorption processes [pressure sewing adsorption (PSA)] leum refineries in conversion and finishing processes such
would be suitable for lower acid concentrations and might as hydrocracking, hydrotreating, hydroconversion, and
be used when it is required to reduce acid concentration hydrofinishing for the upgrading of heavy ends. Chapter 12
to a very low level [12]. Water in natural gas is usually is devoted to the production and management of hydrogen
separated by absorption of water vapor through a solvent in the petroleum industries. This chapter first provides an
such as triethylene glycol (TEG). Heavier hydrocarbon overview of various technical aspects in refinery hydrogen
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Chapter 1 n Introduction 11

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 1.8—(a) Natural gas processing and (b) gas sweetening plants [11].

management, including basic information for hydrogen 1.5 Design and Operation of Refining and
production, purification, transportation, and distribution. Natural Gas Processing Units
Because hydrogen supply becomes a bottleneck issue for Refineries and gas processing plants are complex indus-
many refineries to deal with stricter product specifica- tries involving hundreds of units and pieces of equipment
tions and a higher degree of heavy oil upgrading, a good assembled together. The main process units include fur-
hydrogen management practice becomes very important naces; heat exchangers; distillation, absorption, and strip-
to maintain the competitiveness of a refinery. Therefore, a ping columns; separators; extraction units; and various
systematic approach, namely hydrogen pinch analysis, is types of reactors. Additionally, storage facilities, pipelines,
introduced. It contains two steps—targeting and design—in pumps, compressors, and control units, among many other
which the targeting step quickly identifies the maximum smaller components, are required. Optimal, economical,
hydrogen saving potential and the design step tries to and safe operation of these units first requires careful
exploit all possible design options to reach the target on the design practices. A discussion of the detailed design of such
basis of mathematical programming. Details of the hydro- units requires a dedicated handbook of process unit design.
gen pinch analysis technology are explained. Hydrogen Chapter 13 gives a basic overview of design methods and
undoubtedly is the best example of a perfect fuel. Having calculations as well as specific methods for the major sepa-
the highest heating value of any fuel on a mass basis as not ration units and heat transfer equipment used by process
releasing any carbon to the atmosphere upon combustion, engineers in the industry.
it may play a role in energy future directions, as described Reducing variability and enhancing process capability
in several chapters of this book. are the two distinctive imperatives in the competitive world
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12 Petroleum Refining and Natural Gas Processing

Figure 1.9—General scheme of natural gas processing [5].

Air Separation

Oxygen
Fischer-Tropsch
Partial Synthesis
Separation

Oxidation Naphtha + Distillates

+ 190°C-250°C 10 000 bbl/y
Steam 10-40 bar 425 000 t/y
Reforming H2/CO = 1.5-3
Natural Gas Catalyst:Co,Fe Fuel Gas
100 000 Hydro-
Nm3/h isomerization Naphtha
Separation

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Kerosene
Water
250°C-350°C Gas Oil
P < 100 bar
Lube Oil
Catalyst: Pt
Specialties

Wax

Syngas Production Investment: 55 FT Synthesis 30 % Hydroisomerization and Separation 15 %

% (ISBL, Inside Battery Limits)

Figure 1.10—Natural gas upgrading: FT synthesis integrated GTL process [13].

of any manufacturing industry. Over the years, process rocess control, etc., could be dovetailed on a real-time basis
p
control and instrumentation coupled with ever-increasing with relative ease to fulfill the performance set.
online computing power have brought about a paradigm Chapter 14 helps readers obtain insight into basic pro-
shift in addressing these business objectives. Concepts such cess control approaches in manufacturing industries start-
as global optimization, early event detection, geometric ing from simple feedback control to more advanced process
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Chapter 1 n Introduction 13

H2 Rec. Stream

Natural Gas H2 Production,

& Refinery Hydrodesulfurization Reformer HT Shift PSA 99.9 %
Offgas

Natural Gas Fuel PSA Purge

CH4 + H2O CO + 3H2O CO + H2O H2 + CO2

Figure 1.11—Natural gas to hydrogen production process schemes (PSA technology) [16].

control procedures, integrating the latest model-based quality the microprocessor and its associated distributed control
measuring instruments such as near-infrared (NIR) analyzers systems (DCS) became available. The intention is not to
for accurate and fast sample measurement for tighter con- provide an academic theory of control, but to provide suffi-
trol, enabling reduced “quality giveaway.” Appropriate case cient base knowledge and practical configuration examples
studies are included for better understanding of the various of what has actually worked in real-life applications for
controls as practiced in manufacturing industries. Reliabil- most of the major refining units. Briefly, Chapter 14 focuses
ity assurance of instrumentation and refinery of the future on process control overview, from the basic elements to
concepts are also discussed in Chapter 14 in order to trigger model predictive control, with case studies presented for
more concentrated efforts in the future on these topics. some key units such as FCC or crude distillation units,
Because of the importance of process control in mod- whereas Chapter 15 provides the basis for understanding
ern refineries, Chapter 14 is followed by another chapter the key role of APC to meet refinery safety, operational, and
on unit control. Chapter 15 on modern computer process economic objectives, with examples of application for most
control provides a basis for understanding the various of the major refinery units.
control technologies and their levels of integration, with Although unit design and operations have been pre-
the objective being to design and implement advanced sented in Chapter 13, almost every chapter in which various
process control (APC) applications that can help improve processes are discussed includes a discussion on the design
the operational profitability of the process units in a safe and operation of such units in further detail. For example,
manner. The mix of technologies consisting of advanced additional references to process design and operation have
regulatory control (ARC), conventional control, multivari- been included in Chapters 6 and 10 where FCC and other
able predictive control (MVPC)/model predictive control conversion-type processes are discussed, in Chapters 11
(MPC), inferential predictions, fuzzy logic control, advisory and 12 on natural gas processing and hydrogen production,
systems/abnormal situation management (ASM), and arti- as well as in chapters related to process simulation and con-
ficial neural networks (ANN) allows us to monitor, control, trol, corrosion, and alternative feedstocks such as heavy-oil
and optimize during the normal operating process condi- processing and biorefineries.
tions and during periods of fast ramping, feed changes, Maintenance and inspection functions in a refinery
and unplanned events. Such APC applications have now are the backbone for safe and reliable plant operations
become a norm for refining and petrochemical units, with and play a pivotal role in achieving the desired produc-
several thousand implemented since the mid-1970s when tion target and profitability to the company efficiently;
these are discussed in Chapter 16 in detail. Maintenance
functions in the refinery constitute mechanical, electrical,
instrumentation, and civil functions that are responsible
for the monitoring, repair, and maintenance of equipment
in its respective defined areas. Preventive maintenance,
predictive maintenance, structured repair system, and full-
fledged plant shutdown management are the necessities of
reliability. Each type of maintenance activity that needs to
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

be followed in an operating refinery or when the plant or

units have been shut down as per plan has been covered
here in detail. Efforts have been made to cover each type of
maintenance such as preventive, predictive, and shutdown
maintenance in this chapter and each one of them has been
explained in detail. In the case of electrical and instrument
equipment, emphasis has been placed on explaining the
maintenance activities required to be performed on all
major equipment along with general guidelines to be fol-
lowed for making systems more reliable. Chapter 16 cov-
Figure 1.12—A hydrogen plant in Belgium with a capacity of ers the various methods of inspection techniques that are
10,000 m3/h [17]. followed in a refinery.
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14 Petroleum Refining and Natural Gas Processing

Corrosion inspection and control are discussed in industry standards and governing ASTM test methods.
Chapter 17. Metallic materials used to manufacture equip- Products are analyzed using laboratory analysis, online
ment for the petroleum refining industry are subjected to analyzers, and model predictive methods. Chapter 18 dis-
a wide variety of potential damage mechanisms, the most cusses all important aspects of product analysis and qual-
common being corrosion and environmental stress corro- ity control, testing method standards, key specifications,
sion cracking. The safe operation of oil refineries depends etc. The cost of laboratory analysis is quite significant in
on understanding these degradation mechanisms, making a refinery, and Agrawal [19] has suggested a method to
the proper material selection, devising corrosion control, estimate laboratory analysis load and its cost and differ-
inspection programs for earlier detection of problems, and entiate between the cost of laboratory analysis separately
monitoring material performance. Dry and wet corrosion for onsite (process units) and offsite operations. In a case
are discussed in this chapter. Damage mechanisms other study of a 300-kbbl/day refinery, Agrawal [19] has demon-
than corrosion are also described in their connection with strated and it is shown in Figure 1.14 that many process
particular refining processes. streams require laboratory analyses for onsite opera-
tions but are less in frequency, whereas offsite operations
1.6 Refinery Offsite Operations and require less laboratory analyses of tanks but are more in
Transportation frequency.
A typical refinery or any liquid-based processing plant oper- Chapter 19 in this book discusses fuel blending tech-
ations are categorized as onsite or offsite operations. The nology, management of a blending project, and many
onsite activities are mainly concerned with safe, efficient, important topics such as linear and nonlinear blend mod-
and optimized operations of process and ancillary units, els, methods to handle blend nonlinearity, concepts of a
whereas the offsite activities focus on crude blending, fuel recipe optimization and planning process in a refinery, etc.
blending, tank farm management, oil movement, terminal After the fundamental concepts are reviewed, the chapter
operations, etc. Typically, 80–85 % of refinery products for discusses the design aspects of a blending project for the
the end users are made in the offsite operations; hence, automation of field equipment and instrumentation, hard-
they can severely affect the refinery bottom line if these ware, software, and blending tank quality measurement.
offsite activities are not designed, planned, and executed in The chapter concludes with methodologies to estimate
an orderly and efficient manner. It is not uncommon that various sources of errors and assess the current state of
a refinery spends huge investments to optimize its process blending and the successful implementation of upgrade or
units and loses it all in outdated and inefficient offsite revamp of a blending system. It is estimated that an inte-
operations or both. Figure 1.13 shows a schematic diagram grated fuel blend control and optimization system can save
of refinery onsite and offsite operations [18]. on average 15–45 cents/bbl of gasoline production, amount-
It is of utmost importance for a refinery to produce ing to $7–22 million/year in savings for a 300-kbbl/day
and sell products with strict quality adherence following refinery. Figure 1.15 shows the various functional modules

Figure 1.13—Integrated onsite and offsite operations [18].

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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Chapter 1 n Introduction 15

Lab Sample/Analysis Frequency Distribution for a Typical Refinery

Data Used from an Actual Refinery
20

18
OFFSITE ONSITE
OPERATIONS OPERATIONS
16

14
Frequency / Year

0
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

SQS=NSource*NQuality*NSample
Figure 1.14—Typical distribution of laboratory analyses load for onsite and offsite operations [19].

Automatic
8
Offline Blend Optimizer &
9
2 Tank Gauging Distributed Control
System (DCS)
Scheduling System
Online Blend Control & End Product
System 7 Advanced
Control System
Optimization
Dispatch
Regulatory Blend Control

Online Analyzers &

Sampling System
Tanks

6
Product

B
L Tankers
Stocks

M E
N
M M M
M

M
S

D
M

M M

4
M M

E
M

1 Tank Farm
Field Equipment / R
Pipelines

Instrumentation
S
K Trucks
I
Total Blend Flow , M3
Blend Target Rate , M3/Hr
8000
2000
BLEND
HEADER
TV-124

Heel, M3
Volume, M3
1000
9000
Maximum, M3 12000
6 D
LEADED

ADDITIVES CONCENTRATIONS
UNLEADED

Units Spec Current

ANILINE Aniline mg / lit 2 1.95
FI2109 Detergent mg / lit 280 275
PV 3.95 LIT /HR TEL ml / gal 1 0.956
SP 3.96 LIT /HR
M
F 13.86 LIT/HR FI2212
SDV2115 D PV 608.7 LIT/HR

3
SDV2115A
SP 608.7 LIT/HR M
2115 -P F 2130.4 LITS
M M SDV2112 A
SDV2115 B
2113-P
SDV2115 C SDV2109 B
M
2115 -PA
SDV2112B
LEAD

Rail
2113-PA
FI2113 FI2211
FI2210 PV 0
DETERGENT
PV 2.3266 GPM
SP 2.3266 GPM PV 42.326 GPM SP 0 M
F 600.58 GALS F 15000.58 GALS F 0
M SDV2111 A

2114 -P

Laboratory
TEL SDV2113 SDV2109 A
M

Wagons
SDV2111 B
DILUTANTS 2114 -PA

5 Additive Control
System

Figure 1.15—Integrated fuel blending control and optimization system modules.

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16 Petroleum Refining and Natural Gas Processing

of an integrated blend control and optimization system that vessels and ports at a global scale. However, at some point
are discussed in detail in Chapter 19 of this book. the marine network relies on inland transportation systems
Chapter 20 discusses all technical and management for the final distribution of goods to the markets. For the
aspects of a tank farm in a typical refinery. It starts with case of inland fluid transportation, one of the most effective
the discussion of various types of tanks such as the cylin- and efficient means of transportation is the use of pipelines.
drical and spherical tanks used in a typical refinery. It then
presents design methodologies to estimate the storage 1.7 Refinery Planning and Scheduling
requirement on the basis of refinery complexity and mode Planning and scheduling are two distinct activities in refin-
of crude and product receipts and dispatch. The chapter ery operation and management. Planning “plans the work”
also discusses process parameters, their methods to mea- and scheduling “works the plan.” Planning has a very wide
sure them by a tank gauging system, and how to calculate time horizon from 1 to 3 months at the corporate and
tank inventory using these measured parameters. Next, the refinery levels whereas scheduling works on 1- to 2-day
methods and technology to measure/estimate tank qualities time periods. Planning cycles are further broken down
and fugitive emissions are discussed in the chapter. The into weeks and days by the refinery planner and blend-
chapter discusses the oil movement and storage system in ing- and oil-movement engineers. The information needed
a refinery and presents the design concept, control technol- for planning cycles is the best estimate of parameters and
ogy, and economic analysis to justify and implement an oil process data and is tuned with the reconciliation and feed-
movement and storage (OM&S) project. Lastly, it covers back strategy whereas scheduling is refined and readjusted
refinery terminal operations and enumerates the problems to suit operation constraints and the dispatch schedule.
and challenges of each of the terminals—marine, truck, Figure 1.16 shows the flow of information from planning
railcar, and pipeline terminals. to execution and feedbacks from actual execution data to
Chapter 21 covers the transportation of crude oil, planning for reconciliation of “plan versus actual.”
natural gas, and petroleum products. Almost the entire The refinery planning process involves the building of a
operation for the transportation of oil and gas takes place refinery model of all process units and solves and optimizes
in one of two modes: pipeline transportation for inland and the process parameters on the basis of physical and process
transcontinental trade and marine transportation (tankers) constraints. This is done using linear or nonlinear program-
for international or intercontinental trade. Ocean tankers ming techniques or both. Chapter 22 gives an overview of
provide the most common method of internationally mov- these mathematical techniques to optimize the refinery
ing petroleum products. Marine transportation systems, or planning process and illustrates it with an example of a
tank fleets, are the primary option available for the long- simple refinery configuration.
distance transportation of internationally traded energy The second part of Chapter 22 discusses the concept of,
commodities because they make use of a vast network of given a monthly plan of production and supply targets with

MONTHLY WEEKLY DAILY TODAY FEEDBACK

• Price forecasts • Weekly prices • Weekly •Unit yields • Plan vs actual
(crude/products/ (crude Economics •Maintenance Unit yields
feedstocks) /products) • Constraints /rates •Ullage • Lost profit
• Constraints/rates
•Constraints • Qualities/yields •Demurrage opportunity
• Maintenance
•Yields • Ullage
REFINERY • Demurrage
SUPPLY PRODUCTION OPERATING
OPERATING • Inventories
PLAN PLAN DATA
PROGRAM
• Pricing plan
•Lifting • Qualities/yields • Short term •Immediate vs actual
schedule • Ship/mainline/ Maintenance liftings (48 hrs) • Giveaway
•Trading RTW • Immediate •Inventories • Utilisation
opportunities nominations liftings (48 hrs) •Blend recipes • Availability
• Inventories
•Term deals • Inventories & sequences • KPI ’s
• Crude blends
••Inventories • Blend recipes • Mass balance
• Product blends
•Product blends

Blend
Software Refinery-wide Offline Blend Offline Blend Online Blend Information and
Applications LP Model Optimizer Optimizer Optimizer Feedback
System
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 1.16—Stages of typical refinery planning cycles [18].

AST-MNL58-11-0801-001.indd 16 3/12/13 12:25 PM

Chapter 1 n Introduction 17

crude and product recipes, how to schedule activities such Whitel [20] has most recently published an interest-
as tank swings, oil movement, and blending productions to ing article on the role of automation in energy-saving in
minimize any severe effects on the refinery bottom line. The chemical plants. Petroleum refineries and petrochemical
chapter also discusses tools and techniques to implement plants are large energy consumers—with energy second
an efficient and effective scheduling system in the refinery only to feedstocks as a variable operating cost. For exam-
and integrate it with the planning system. ple, a 5 % energy saving is worth over $4 million/year in
increased operating margin for a typical North American
naphtha-feedstock plant producing 500,000 t/year ethyl-
1.8 Refinery Economics and Financial

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
ene with an energy cost of $6 per million Btu (MMBtu).
Risk Management
Feed type and quality, product composition, and configu-
The refining industry is a global business, and its survival
ration all affect the energy use of the plant. The difference
purely depends on its profitability and competitiveness.
between energy consumption of the most efficient and
The most profitable refinery is the one that can convert the
least efficient plants could be as high as 40 %. Surveys
heaviest crude oils into the lightest petroleum products.
have also shown that the most important factor that
Chapter 23 presents a primer on the concepts, systems, and
affects energy use is the age of a plant, with the implica-
mechanisms of the trading, costing, pricing, and valuation
tions in inspection and maintenance. Advanced control
of crude oils and petroleum products. The roles of costs
and optimization also have a significant effect on poten-
and profit margins for economic evaluations in the refin-
tial energy savings. Basic and advanced process control
ing industry are discussed in this chapter. For a complete
systems in the refining industry are discussed in several
treatment, it is shown how oil markets have operated and
chapters of this book.
evolved historically in terms of how the refining industry
Chapter 26 covers the current process simulation
has developed from purely physical trading to a sophis-
model building and application in refineries. Market com-
ticated financial market. Crude oil pricing mechanisms;
petition in the refining industry is encouraging companies
product trading, pricing, and valuation; operating costs;
to optimize their processes to maximize margins and make
raw material supply; capital costs; refinery profit margins
better products while meeting more stringent constraints to
and costs; and relations between refinery margins and
comply with safety and environmental regulations. Simula-
product pricing are discussed in this chapter. Economical
tion models may be consistently applied from planning the
issues related to the refining industry are followed in Chap-
production to managing the operation, and even in process
ter 24, which discusses the complexity of modern refineries
control, depending on the desired time horizon and provid-
with respect to market restrictions. Refinery processes and
ing the level of detail of the model to allow this flexibility, to
operations are classified with respect to product demand
support refining companies in this challenge.
and supply statistics in the United States and the world.
The chapter focuses on some of the key aspects in
Investment cost curves are presented and the methodologi-
building simulation models for refining processes. Applica-
cal framework, data sources, and normalization procedures
tions of process simulation technologies in different areas
used in estimation are described, followed by a discussion
of refinery operation (planning and scheduling, process
of the limitations of analysis.
engineering, and process control) are reviewed. Emphasis
Chapter 25 introduces concepts of financial risk as
is placed on adequate technologies for fast and flexible
applied to decision-making associated with refinery opera-
updated stream characterization and rigorous thermo-
tions. Particular focus is given to the use of two-stage
dynamic calculations, which are critical to guarantee
programming to make crude purchasing decisions as well
model reliability. These issues as well as model building
as operational choices such as the throughput of differ-
techniques and future trends in modeling technologies are
ent units. Most models consider the price as an external
presented in Chapter 26.
uncertain parameter. In addition, techniques to identify
Chapter 27 is devoted to maintenance simulation
decisions that are less profitable, but also less risky, are
and optimization in refinery plants. A typical refinery
presented. Finally, it is shown how commercial software
experiences approximately 10 days of downtime per year
can be utilized. It is therefore concluded that the techniques
because of equipment failures, resulting in an estimated
presented are mature and ready to be adopted in practice to
economic loss of tens of thousands of dollars per hour.
run refinery businesses with lower financial risk.
Therefore, appropriate maintenance actions are of para-
mount importance from a safety and economic point of
1.9 Characteristics of Modern Refineries view. Once safety levels have been achieved through appro-
Modern refineries are characterized by their capability priate maintenance, the question is how much preventive
of converting heavier oils into more light- and middle- maintenance is economically advisable. Maintenance is
distillate products with little or no residues and production defined as all actions appropriate for retaining an item/
of higher quality fuels with ultralow sulfur contents. Eco- part/equipment in, or restoring it to, a given condition. The
nomical, environmental, and safety factors are priority con- annual cost of maintenance (corrective and preventive) as
siderations in modern refinery management. All of these a fraction of total operating budget can go up to 20–30 %
challenges are not only achieved by considering advanced, for the chemical industry as discussed in Chapter 27. This
more efficient processes and more conversion units (FCC chapter also outlines recent efforts to perform Monte
and hydrocracking) with improved new catalysts, but also Carlo simulation to obtain an assessment of the effect of
with an intensive use of simulation and optimization tools existing corrective and preventive maintenance practices
in planning and operation as well as the implementation incorporating details of the available labor, task assign-
of more advanced control systems throughout this com- ment rules, and parts inventory on plant economics. The
plex industry. performance of a genetic algorithm in conjunction with
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18 Petroleum Refining and Natural Gas Processing

the Monte Carlo simulation is illustrated using the data activities that apply today and that serve to minimize the
from an FCC plant. impact of the hazards typically associated with petroleum
This critical role of computers and computerized sys- refining. The driving forces behind much of what makes up
tems, which has led to the implementation of APC in today’s a modern safety and health program in the petroleum refin-
refineries, is emphasized from a slightly different focus in ery in the United States are the regulatory agencies—the
Chapter 28, which presents an integrated vision on the role Occupational Safety and Health Administration (OSHA)
of computers and automation in refinery operation. The and the U.S. Environmental Protection Agency (EPA). This
application of computer-aided process operation systems in chapter will draw heavily from these regulations.
process design and control, operations planning, schedul- Chapter 31 discusses the management of the refining
ing, and optimization has revolutionized modern refineries industry in conjunction with economic and environmental
into integral entities with a degree of efficiency difficult constraints. One of the main challenges in the refining
to imagine without the implementation of these advanced industry is to maximize crude utilization at minimum cost
information technology (IT) applications. while meeting regulations and customer requirements. The
refinery’s leadership must possess a range of leadership
1.10 Environmental and Safety Issues qualities, preferably personally in the refinery manager,
Like any other major industry, the refining industry must but if not, then certainly amongst his small cadre of senior
sustainably operate under economically competitive and managers upon whom he can rely. The refinery’s manage-
environmentally responsible management. New regula- ment is further faced with an increased variety of crude
tions, particularly in developed countries, require stricter oils (heavier, more sulfur), an increased complexity of
regulations and laws on fuels and pollutant emissions. operations from an increased diversity of products, tighter
The state of the world economy strongly affects energy rules on product specifications and lower sulfur content,
markets. The availability of feedstocks and markets for the uncertainty in future refinery margins (ups and downs),
products affects the economics of the refining industry. and positive average growth. Chapter 31 addresses these
Many industries tend to shift from one region to another challenges and provides a suite of proven practices for suc-
because of new environmental regulations or varying mar- cessful refinery management.
ket conditions. For example, global climate change has
been cited as a reason for closing some refineries in the 1.11 Biorefining
United States. However, although smaller refineries have Biofuel is a renewable form of energy that refers to fuels
been shut down, larger refineries expanded and overall that can be produced from biological raw material (bio-
refining capacity has risen by 13 % since the 1980s in mass). Forest and agricultural resources are the main bio-
the United States. The recent recession, use of alternative mass resources. At present, biomass provides 3 % of the
fuels (ethanol and biofuels), and the manufacture of more total U.S. energy consumption, in comparison with 39 %
efficient cars caused a reduction in gasoline consumption (oil), 24 % (gas), 23 % (coal), 8 % (nuclear), and 3 % from
in recent years in the United States and some other indus- other forms of renewable energy such as hydro, geother-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

trialized countries. mal, wind, and solar energy. However, this proportion
Environmental issues in refineries concerning water, will change rapidly in coming decades, supported by new
air, and noise pollution and the associated pollution reduc- legislation, especially in developed countries. In 2007, the
tion and treatment methods are discussed in Chapter 29. U.S. government announced a target of reaching in 2030
Environmental considerations are increasingly affecting a 30 % substitution of transport fuel consumption by
the bottom line of petroleum refineries (i.e., refining mar- alternative fuels, mainly biofuels. In the European Union,
gins) and thus should be taken into account in the design the target of 5.75 % of total European transport fuel con-
and operation of refineries. Chapter 29 is divided into sumption coming from biofuels in 2010 was reviewed in
three main parts, each addressing the three major types 2007 and 2008, allowing for higher biodiesel content in
of environmental pollution related to the operations of a commercial diesel and more challenging objectives for
refinery: water pollution, air pollution, and noise pollution. 2020. Similar legislations have been proposed in other
The chapter concludes with a general outlook of the shape countries around the world. The International Energy
of events to come, particularly in view of the anticipated Agency (IEA) has forecasted an average 4–7 % of the total
impending massive effects of global climate change. road transport world consumption in 2030 coming from
Chapter 30 reviews safety issues related to petroleum biofuels.
refineries. In petroleum refineries, safety concerns focus On the basis of 2004 data from the U.S. Department
on two main areas: process safety and labor or person- of Energy, the annual rate of biomass consumption is
nel safety. Process safety involves the risk assessment and 190 million dry tons, of which 35 million t is fuel woods and
development and implementation of intervention plans 18 million t is biofuels. In the United States, biomass con-
concentrated on preventing or minimizing the risks from sumption in the industrial sector will increase at an annual
loss of containment of flammable, toxic, or reactive chemi- rate of 2 % through 2030. Additionally, biomass consump-
cals. Labor or personnel safety interventions focus on the tion in electric utilities will double every 10 years through
operational procedures for the prevention or mitigation of 2030. Biopower will meet 5 % of the combined total indus-
hazards that can result in individual injuries or exposures. trial and electric generator energy demand in 2020. Trans-
Both approaches to safety attempt to prevent or minimize portation fuels from biomass will increase significantly
the impact of accidents. Over the last 20–30 years, in petro- from 0.5 % of the U.S. transportation fuel consumption
leum refineries and similar processes, there have been in 2001 to 10 % in 2020 and 20 % in 2030. Production
several significant watershed incidents that have fueled the of chemicals and materials from bio-based products will
development of many of the regulations and prevention increase substantially from approximately 12.5 billion lb
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Chapter 1 n Introduction 19

or 5 % of the current production of target U.S. chemical

commodities in 2001 to 12 % in 2010, 18 % in 2020, and Table 1.7—A Comparison between
25 % in 2030 [21]. The European Union (EU) is the main Key Parameters of Biodiesel Fuel and
consumer and producer of biodiesel, whereas the United Conventional Fossil Fuel Diesel [24]a
States and Brazil are the main producers and consumers of Fuel Property Diesel Biodiesel
bioethanol. Biomass is expected to become one of the major
Fuel standard ASTM D975 ASTM D6751
renewable resources for the production of feed, materials,
chemicals, fuels, power, and heat. The global potential sup- Kinetic viscosity at 40°C, mm /s 2
1.3–4.1 1.9–6.0
ply of biomass for energy use is very large.
Specific gravity at 60°C, kg/L 0.85 0.88
Some of the key drivers to support this growth are
consumer requirements for end products, nonrenewable Density, lb/gal 7.079 7.328
fossil resource reduction, cleaner and safer chemical manu- Water and sediment, % vol 0.05 max 0.05 max
facturing, and economic improvements of food industry
products by producing added-value products from wastes. Carbon, wt % 87 77
Probably one of the main drivers supporting biofuels is Hydrogen, wt % 13 12
related to climate change policies. The CO2 generated in
fuel combustion is fixed by plants to be converted again in Oxygen 0 11
biomass. Although not completely renewable (some energy Sulfur, wt % 0.0015 0.0–0.0024
is consumed in the process), in essence the carbon balance
Boiling point, °C 180–340 315–350
is very favorable compared with conventional fossil fuels.
However, the generalized use of biofuels as an alternative Flash point, °C 60–80 130–170
energy has caused major concerns related to competition
Cloud point, °C –15 to 5 –3 to 12
with food and pressure on land resources. Although some
improvement has been made, the biofuel industry needs Pour point, °C –35 to –15 –15 to 10
an internationally recognized and accepted certification
Cetane number 40–55 47–65
scheme related to sustainability criteria.
According to IEA Bioenergy Task 42, biorefining is
a
On average based on European standards from several studies.

defined as the sustainable processing of biomass into a

spectrum of marketable products and energy [22]. On the
basis of this definition, seven types of biorefineries have or cyanobacteria. However, the challenge to commercially
been recognized: (1) conventional biorefineries, (2) green develop second- and third-generation biofuels requires a
biorefineries, (3) crop biorefineries, (4) cellulosic feed- significant effort in research and development.
stock biorefineries, (5) two platform concept biorefineries, The increasing role of biofuels in the energy market
(6) thermochemical biorefineries, and (7) marine-type bio- makes them appear in different chapters in this book.
refineries, as discussed in reference 23. Statistical data on biofuels are covered in Chapter 3. Some
In a petroleum refinery, crude oil is converted into fuels specifications and properties of biofuels are given in Table
(i.e., gas, gasoline, kerosine, etc.) and some non-fuel-type 1.7 [24], but further details on biofuel properties are dis-
chemicals (i.e., waxes, solvents, etc.). In a biorefinery, bio- cussed in Chapter 4 whereas biofuels for transport and
mass is converted into fuels such as bioethanol, biodiesel, their biorefining processes are discussed in Chapter 32.
biogas, and hydrogen as well as non-fuel materials such Finally, additional discussion on characteristics of
as basic and fine chemicals, biopolymers, and bioplastics. future refineries is presented in Chapter 33. In this last
Many existing industries such as the sugar industry (from chapter, after a brief review of refinery processes, several
beet, cane) or vegetable oil from soy, pulp and paper from configurations proposed for future refineries and some
forest, biodiesel, and bioethanol industries fall into the cat- new developments in the field are presented. Environmen-
egory of conventional refineries. Biodiesel can be produced tal and economical constraints, feedstock quality, product
from vegetable oils and animal fats via chemical processing specifications, and process flexibility are considered in such
and transesterification using ethanol, catalyst, and separa- future refinery scenarios.
tion of methanol and produced biodiesel. In this process,
glycerin is also produced. A typical thermochemical route 1.12 Importance of the Book
to biofuel involves gasification of biomass to syngas fol- The downstream processing of petroleum and natural gas
lowed by catalytic Fischer-Tropsch conversion to biodiesel is a complex and huge industry that converts raw materi-
as demonstrated by Ladisch et al. [24]. als (mainly petroleum and natural gas) into a series of fuel
According to the efficiency of the process to convert and non-fuel products. The industry includes field process-
biomass, it is widely accepted today to refer to “first- ing, refining, and processing; fuel blending and quality
generation” biofuels when only a fraction of the raw mate- control; and storage and transportation of feedstocks and
rial is converted (leaving significant amounts of byproducts products. Construction and sustainable operation of such
or residua not used for energy purposes), compared with industries involves detailed engineering and scientific
future “second-generation” biofuels, which opens the range tasks. The full coverage of these areas in a single book is a
of vegetal species and focuses on maximization of raw difficult task, if not impossible, as evident from the series
material use. The focus in fast-growing plants, including of books published in the last 2 decades in this area for
marine crops, algae, and cyanobacteria, has made some educational purposes or certain industrial sectors [26–38].
refer to “third-generation” biofuels if or when the raw mate- In fact, topics covered in each chapter of this handbook
rials will be from plants genetically designed or from algae require a full book in themselves for detailed discussion.
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20 Petroleum Refining and Natural Gas Processing

However, this book attempts to discuss additional aspects Congress of Chemical Engineering, Glasgow, Scotland,
of these industries with updated information by leading 2005.
world experts in each field from industry and academia. [15] Davis, B.H., “Fischer-Tropsch Synthesis: Overview of Reactor
Development and Future Potentialities,” Topics Catal., Vol. 32,
Great emphasis is given to the processing of heavy oils, new 2005, pp. 143–168.
processes, environmental and economical considerations, [16] Davis, R.A., and Patel, N.M., “Refinery Hydrogen Manage-
planning and scheduling, process control and automa- ment,” Petrol. Technol. Quarter., Vol. 9, 2004, pp. 29–35.
tion of refining units, maintenance and safe operation of [17] Rostrup-Nielsen, J.R., and Rostrup-Nielsen, T., “Large-Scale
process units, quality control and product analysis, fuel Hydrogen Production,” Cattech, Vol. 6, 2002, pp. 150–159.
and crude oil blending control and optimization, and tank [18] Offsite Management Systems, LLC, Strategic Fuels Blending
Technology and Management-Training Manual, Offsite Man-
farm management. In addition, alternative fuels such as agement Systems, LLC, Sugar Land, TX, 2009.
hydrogen and biofuels in relation to petroleum fuel and the [19] Agrawal, S.S., “Advances in Tank Quality Measurements Can
petrochemical industries have been given special attention Help Cut Operational Costs,” Hydrocarbon Process., Vol. 86,
and are covered in separate chapters. A vision of trends in 2007, p. 67.
petroleum processing toward future refineries is covered [20] Whitel, D.C., “Save Energy through Automation,” Chem. Eng.
Prog., Vol. 106, 2010, pp. 26–33.
in the last chapter. The book should be useful to people
[21] U.S. Department of Energy and U.S. Department of Agricul-
from industry and academia as well as environmentalists ture, Biomass as Feedstock for a Bioenergy and Bioproducts
and those from the transportation and automobile indus- Industry: The Technical Feasibility of a Billion-Ton Annual Sup-
tries, governments, business people, investors, economists, ply, U.S. Department of Energy, Washington DC, 2005, http://
managers, process engineers, operators, and policy- and www.biorefinery.nl/fileadmin/biorefinery/docs/Biomass_as_
feedstock.pdf.
decision-makers.
[22] “IEA Bioenergy Task 42 Biorefineries,” http://www.IEA-Bioen-
ergy.Task42-Biorefineries.com (accessed May 11, 2011).
Acknowledgments [23] Van Ree, R., Annevelink, E., Tatus Report Biorefinery 2007,
The authors thank Mohan S. Rana of the Kuwait Institute SenterNovem, René van Ree & Bert Annevelink, Report 847,
for Scientific Research for providing some of the figures ISBN-number 978-90-8585-139-4, November, 2007, http://
and tables related to fuel quality and refining processes as www.biorefinery.nl/publications/.
[24] Ladisch, M.R., Mosier, N.S., Kim, Y., Ximenes, E., and Hog-
cited in the text. sett, D., “Converting Cellulose to Biofuels,” Chem. Eng. Prog.,
March, 2010, pp. 56–62.
References [25] U.S. Department of Energy, Biodiesel Handling and Use
[1] Speight, J.G., The Chemistry and Technology of Petroleum, 3rd Guidelines, 2nd ed., U.S. Department of Energy, Washington,
ed., Marcel Dekker, New York, 1998. DC, 2006 or Crimson Renewable Energy, LP, “Biodiesel Fuel
[2] Mansoori, G.A., “A Unified Perspective on the Phase Behavior Specifications and Comparison to Diesel Fuel,” http://www
of Petroleum Fluids,” Int. J. Oil Gas Coal Technol., Vol. 2, .CrimsonRenewable.com.
2009, pp. 141–167. [26] Fahim, M.A., Al-Sahhaf, T.A., and Elkilani, A., Fundamentals
[3] Arnold, K., and Stewart, M., Surface Production Operations, of Petroleum Refining, Elsevier, Amsterdam, The Netherlands,
2nd ed., Gulf Publishing, Houston, TX, 1998. 2009, p. 516.
[4] Riazi, M.R., Characterization and Properties of Petroleum Fractions, [27] Leffler, W.L., Petroleum Refining in Nontechnical Language,
MNL50, ASTM International, West Conshohocken, PA, 2005. 4th ed., PennWell Corporation, Tulsa, OK, November, 2008,
[5] Rana, M.S., Personal communications, Kuwait Institute for p. 270.
Scientific Research (KISR), Division of Petroleum Refining, [28] Sarkar, G.N., Advanced Petroleum Refining, 1st ed., Khanna
Kuwait, March 2010. Publishers, New Delhi, India, 2008, p. 628.
[6] U.S. Energy Information Administration, U.S. Department of [29] Gary, J.H., Handwerk, G.E., and Kaiser, M.J., Petroleum Refin-
Energy, “Official Energy Statistics from U.S. Government,” ing: Technology and Economics, 5th ed., CRC, Boca Raton, FL,
2009, http://www.eia.doe.gov/emeu/international/reserves.html. 2007, p. 488.
[7] Riazi, M.R., “Energy, Economy, Environment and Sustainable [30] Jones, D.S.J., and Pujadó, P.P. (Eds.), Handbook of Petroleum
Development in the Middle East and North Africa,” Int. J. Oil Processing, 1st ed., Springer, New York, 2006, p. 1353.
Gas Coal Technol., Vol. 3, 2010, pp. 301–345. [31] Mokhatab, S., Poe, W.A., and Speight, J.G., Handbook of
[8] Peakoil, Australia, http://www.peakoil.org.au, accessed Octo- Natural Gas Transmission and Processing, Gulf Publishing
ber 1, 2009. Company, Houston, TX, 2006, p. 650.
[9] Occupational Safety and Health Administration, Technical [32] Hsu, C.S., and Robinson, P.R. (Eds.), Practical Advances in
Manual Petroleum Refining Processes, Chapter 2, http://www Petroleum Processing, 1st ed., Springer, New York, 2006,
.osha.gov/dts/osta/otm/otm_iv/otm_iv_2.html, accessed Febru- p. 866.
ary 20, 2011. [33] Meyers, R., Handbook of Petroleum Refining Processes, 3rd ed.,
[10] Rana, M.S., Ancheyta, J., Maity, S.K., and Marroquin, G., McGraw-Hill Professional, New York, 2003, p. 900.
“Comparison between Refinery Processes for Heavy Oil [34] Parkash, S., Refining Processes Handbook, 1st ed., Gulf Profes-
Upgrading: A Future Fuel Demand,” Int. J. Oil Gas Coal Tech- sional Publishing, Houston, TX, 2003, p. 688.
nol., Vol. 1, 2008, pp. 250–282. [35] Speight, J.G., and Ozum, B., Petroleum Refining Processes
[11] Natural Gas website, http://www.naturalgas.org/naturalgas/ (Chemical Industries), 1st ed., CRC, Boca Raton, FL, 2001,
processing_ng.asp, accessed March 1, 2011 (original source: p. 728.
Duke Energy Gas Transmission Canada). [36] Maples, R.E., Petroleum Refinery Process Economics, 2nd ed.,
[12] Universal Oil Products, http://www.uop.com. PennWell, Tulsa, Oklahoma, 2000, p. 474.
[13] Courty, P., and Gruson, J.F., “Refining Clean Fuels for the [37] McKetta, J.J., Petroleum Processing Handbook, 1st ed., CRC,
Future,” Oil Gas Sci. Technol., Vol. 56, 2001, pp. 515–524. Boca Raton, FL, 1992, p. 792.
[14] Patel, B., “Gas Monetisation: A Techno-Economic Compari- [38] Nelson, W.L., Petroleum Refinery Engineering, 3rd ed.,
son of Gas to Liquid and LNG,” presented at the 7th World McGraw-Hill, New York, 1949, p. 830.

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2
Feedstocks and Products of Crude Oil
and Natural Gas Refineries
M.R. Riazi1 and Semih Eser2

2.1 Nature and ConstituENTS of The International Union of Pure and Applied Chemis-
Petroleum Fluids try (IUPAC), a nongovernmental organization, provides
As discussed in Chapter 1, petroleum fluids are mixtures standard names, nomenclature, and symbols for chemical
of various hydrocarbons that may exist as gas or liquid in compounds, including hydrocarbons [2].
a petroleum reservoir. The principal elements of petroleum Paraffins are also called alkanes and have the general
are carbon (C), hydrogen (H), and small quantities of het- formula of CnH2n+2, where n is the number of carbon atoms
eroatoms of sulfur (S), nitrogen (N), and oxygen (O). It is in a given molecule. Paraffins are divided into two groups
generally believed that the petroleum hydrocarbons have of normal and isoparaffins. Normal paraffins or normal
been derived from the conversion of organic compounds alkanes are simply written as n-paraffins or n-alkanes,
in some aquatic plants and animals. The most impor- and they are open, straight-chain saturated hydrocarbons.
tant factors that affect conversion of organic compounds Paraffins are the largest series of hydrocarbons found in
to petroleum hydrocarbons are (1) heat and pressure, petroleum and begin with methane, which is also shown
(2) radioactivity such as gamma rays, and (3) catalytic reac- by C1. Figure 2.1 shows several lighter paraffins found in
tions. Vanadium and nickel species are the most effective petroleum fluids [3]. For example, the open formula for
catalysts in the formation of petroleum and are needed for n-butane, n-C4, can be shown as CH3-CH2-CH2-CH3, and for
the conversion reactions. For this reason, these metals may simplicity in drawing, only the carbon-carbon bonds are
be found in small quantities in petroleum fluids. Occasion- drawn and most C-H bonds are omitted.
ally traces of radioactive isotopes such as uranium and The second group of paraffins is called isoparaffins,
potassium can also be found in petroleum. The conditions which are branched-type hydrocarbons and they begin with
required for converting organic compounds into petro- isobutane (also called methylpropane), which has the same
leum are (1) geological time frame in millions of years, closed formula as n-butane (C4H10). Compounds of different
(2) pressure up to 17 MPa (~2500 psi), and (3) temperature structures with the same closed formula are called isomers.
not exceeding 100–120 °C (~ 210–250 °F). In some cases, As shown in Figure 2.1, there are two isomers for butane,
bacteria may have severely biodegraded the oil, destroying three for pentane, and five isomers for hexane (only four are
the light hydrocarbons. An example of such a case would shown in Figure 2.1.) Similarly, octane (C8H18) has 18 and
be the large heavy oil accumulations found in Venezuela. dodecane (C12H26) has 355 isomers, whereas octadecane
Petroleum is a mixture of thousands of different identifi- (C18H38) has 60,523 and C40 has 62 × 1012 isomers. The num-
able hydrocarbons that are discussed in the next section. ber of isomers rapidly increases with the number of carbon
Once petroleum is accumulated in a reservoir or in vari- atoms in a molecule because of the rapidly rising number of
ous sediments, hydrocarbon compounds may be converted their possible structural arrangements, as shown in Figure
from one form to another with time and varying geological 2.2 [1]. It should be noted that many of these isomers may
conditions. The main difference between various oils from not be found in petroleum because they are not thermody-
different fields around the world is the difference in their namically stable. For the paraffins in the range of C5–C12 the
composition of hydrocarbon compounds and impurities [1]. number of isomers is more than 600, although only approxi-
Compounds that only contain elements of carbon mately 200–400 of them have been identified in petroleum
and hydrogen are called hydrocarbons, and they form the mixtures. Isomers have different physical and chemical
largest group of organic compounds found in petroleum. properties. The same increase in number of isomers with
There might be as many as several thousand different molecular weight applies to other hydrocarbon series. As an
hydrocarbon compounds in petroleum reservoir fluids. example, the total number of hydrocarbons (from different
Hydrocarbon compounds have a general closed formula groups) having 20 carbon atoms is more than 300,000 [5].
of CxHy, where x and y are integer numbers. The lightest Under standard conditions of temperature and pres-
hydrocarbon is methane (CH4), which is the main compo- sure (STP), the first four members of the alkane series
nent in natural gas. Methane is from a group of hydrocar- (methane, ethane, propane, and butane) are in gaseous
bons called paraffins. Hydrocarbons are generally divided form, from C5H12 (pentane) to n-heptadecane (C17H36) are
into four groups: (1) paraffins, (2) olefins, (3) naphthenes, liquids, and n-octadecane (C18H38) or heavier compounds
and (4) aromatics. Paraffins, olefins, and naphthenes are exist as wax-like solids at STP. Paraffins from C1 to C40 usu-
sometimes called aliphatic versus aromatic compounds. ally appear in crude oil and represent up to 20 % of crude
1
Kuwait University, Kuwait
2
The Pennsylvania State University, University Park, PA, USA
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21
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22 Petroleum Refining and Natural Gas Processing

have the general formula of CnH2n. If there are two double

bonds, the olefin is called a diolefin (or diene), such as
butadiene (CH2=CH-CH=CH2). Unsaturated compounds are
more reactive than saturated hydrocarbons (without double
bond). Olefins are uncommon in crude oils because of their
reactivity with hydrogen that saturates them; however, they
can be produced in refineries through cracking reactions.
Olefins are valuable products of refineries and are used as
feedstocks for petrochemical plants to produce polymers
such as polyethylene. Similarly compounds with triple
bonds such as acetylene ( CH ≡ CH ) are not found in crude
oils because of their tendency to become saturated [1].
Naphthenes or cycloalkanes are ring or cyclic saturated
hydrocarbons with general formula of CnH2n. Cyclopentane
(C5H10), cyclohexane (C6H12), and their derivatives such
as n-alkylcyclopentanes are normally found in crude oils.
Three types of naphthenic compounds are shown below.

Cyclopentane Methylcyclopentane Ethylcyclohexane

(C5H10) (C6H12) (C8H16)

Figure 2.1—Lighter paraffin hydrocarbons present in If there is only one alkyl group from n-paraffins (i.e.,
petroleum and natural gas [3]. methyl, ethyl, propyl, n-butyl, etc.) attached to a cyclopen-
tane hydrocarbon, the series is called n-alkylcyclopentanes,
by volume. Because paraffins are fully saturated (no double such as the two hydrocarbons shown above where on each
bond) they are stable and remain unchanged over long peri- junction of the ring there is a CH2 group, except on the alkyl
ods of geological time. group juncture, where there is only a CH group. Naphthenic
Olefins are another series of noncyclic hydrocarbons, hydrocarbons with only one ring are also called monocy-
but they are unsaturated and have at least one double cloparaffins or mononaphthenes. In heavier oils, saturated
bond between carbon-carbon atoms. Compounds with one multirings attached to each other called polycycloparaffins or
double bond are called mono-olefins or alkenes and include polynaphthenes may also be available. Thermodynamic stud-
ethene (also named ethylene; CH2=CH2) and propene (or ies show that naphthene rings with five and six carbon atoms
propylene; CH2=CH-CH3). In addition to the structural isom- are the most stable naphthenic hydrocarbons. The content of
erism connected with the location of double bond, there is cycloparaffins in petroleum may vary up to 60 %. Generally,
another type of isomerism called geometric isomerism that any petroleum mixture that has hydrocarbon compounds
indicates the way atoms are oriented in space. The configu- with five carbon atoms also contains naphthenic compounds.
rations are differentiated in their names by the prefixes cis- Aromatics are an important series of hydrocarbons
and trans-, such as cis- and trans-2-butene. Mono-olefins found in almost every petroleum mixture from any part
of the world. Aromatics are cyclic but unsaturated hydro-
carbons with alternating double bonds that begin with a
1.0 × 1015
benzene molecule (C6H6). The name “aromatic” refers to
the fact that such hydrocarbons commonly have fragrant
odors. A group of lighter aromatic hydrocarbons is shown
in Figure 2.3. Although benzene has three carbon-carbon
double bonds, it has a unique arrangement of electrons with
1.0 × 1010
Number of isomers

resonance structures of the double bonds (aromaticity) that

allow benzene to be relatively stable. However, benzene is
known to be a cancer-inducing compound. For this reason,
the amount of benzene allowed in petroleum products such
1.0 × 105
as gasoline or fuel oil is limited by government regulations
in many countries. Under standard conditions, benzene,
toluene, and xylene are in liquid form whereas naphthalene
is in a solid state.
Some of the common aromatics found in petroleum
1.0 × 100
and crude oils are benzene and its derivatives with attached
0 10 20 30 40 50 methyl, ethyl, propyl, or higher alkyl groups. This series
Number of carbon atoms of aromatics is called alkylbenzenes and compounds in
Figure 2.2—Number of possible alkane isomers [1]. this homologous group of hydrocarbons have the general
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Chapter 2 n Feedstocks and Products of Crude Oil and Natural Gas Refineries 23

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Figure 2.4—An example of asphaltene molecule [6].

Such heteroatoms in multiring aromatics are com-

monly found in asphaltene compounds, as shown in
Figure 2.4, where, for simplicity, carbon and hydrogen
atoms are not marked on the rings or on the paraffinic
chains attached to the ring systems.
Sulfur is the most important heteroatom in petroleum
and it can be found in cyclic (e.g., thiophenes) and noncyclic
compounds such as mercaptans (R-S-H) and sulfides (R-S-
R′), where R and R′ are alkyl groups. Sulfur in natural gas is
usually found in the form of hydrogen sulfide (H2S). Some
natural gases contain H2S as high as 30 % by volume. The
amount of sulfur in a crude oil may vary from 0.05 to 6 % by
weight. The presence of sulfur in finished petroleum prod-
ucts is harmful. For example, the presence of sulfur in gaso-
Figure 2.3—Lighter aromatic hydrocarbons present in
petroleum and natural gas [3].
line can promote corrosion of engine parts. The amounts
of nitrogen and oxygen in crude oils are usually less than
the amount of sulfur by weight. In general, for petroleum
formula of CnH2n-6 (where n ≥ 6). Generally, an aromatic oils the elemental composition varies within fairly narrow
series with only one benzene ring is also called mono- ranges, as shown below on a weight basis [5,6]:
aromatics or mononuclear aromatics. Naphthalene and Carbon (C), 83.0–87.0 %
its derivatives that have only two unsaturated rings are Hydrogen (H), 10.0–14.0 %
sometime called diaromatics. Crude oils and reservoir Nitrogen (N), 0.1–2.0 %
fluids all contain aromatic compounds. However, heavy Oxygen (O), 0.05–1.5 %
petroleum fractions and residues contain unsaturated mul- Sulfur (S), 0.05–6.0 %
tirings with many benzene and naphthene rings attached to Metals (nickel, vanadium, and copper), <1000 ppm (0.1 %)
each other. Such aromatics that are in solid form are also Generally, in heavier oils (with lower API gravity) the
called polyaromatic hydrocarbons (PAHs) or polynuclear proportions of carbon, sulfur, nitrogen, and oxygen elements
aromatics (PNAs). In this chapter, the terms of mono- and increase, but the hydrogen content and the overall quality
polyaromatics are used. Heavy crude oils usually contain decrease. A further discussion on the chemistry of petro-
more aromatics than light crudes. The amount of aromat- leum and the types of compounds found in petroleum frac-
ics in coal liquids is usually high, and it could reach as high tions is provided by Speight [6]. Vanadium concentrations
as 98 % by volume. It is common to have compounds with of greater than 2 ppm in fuels can lead to severe corrosion
naphthenic and aromatic rings side by side, especially in in turbine blades and deterioration of refractory in furnaces.
heavy fractions. Monoaromatics with one naphthenic ring Nickel, vanadium, and copper can also severely affect the
have the formula of CnH2n-8. There are many combinations activities of catalysts and result in lower quality products.
of alkylnaphthenoaromatics [4,5]. The metal content may be reduced by solvent extraction
Normally, high-molecular-weight polyaromatics con- with organic solvents. Organometallic compounds are con-
tain several heteroatoms such as sulfur, nitrogen, or oxygen, centrated in the asphaltenes and residues. Some major
but these compounds are still called aromatic compounds low-molecular-weight impurities in crude oil include carbon
because their electronic configurations maintain the aro- dioxide (CO2), H2S, metal oxides [aluminum oxide (Al2O3),
matic character. Two types of these compounds are shown iron(III) oxide (Fe2O3), silicon dioxide (SiO2), etc.], nitrogen
below [1]. (N2), oxygen (O2), salts [sodium chloride (NaCl), calcium
carbonate (CaCO3), etc.], sulfur, and water (H2O) [3].
S
2.2 Reservoir Fluids—Crude Oil
and Natural Gas
The word fluid refers to a pure substance or a mixture of
N compounds that are in the form of gas, liquid, or a mixture
H of liquid and gas (vapor). Reservoir fluid is a term used for the
mixture of hydrocarbons found in a geological petroleum res-
Dibenzothiophene Benzocarbazole (C16H11N)
ervoir or the stream leaving a producing well. Three factors
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24 Petroleum Refining and Natural Gas Processing

Table 2.1—Types and Characteristics of Various Reservoir Fluids [1]

Reservoir Fluid Type GOR (scf/stb) CH4 (mol %) C6+ (mol %) API Gravity of STO

Black oil <1000 ≤50 ≥30 < 40

Volatile oil 1000–3000 50–70 10–30 40–45

Gas condensate 3000–50,000 70–85 3–10 ≥45

Wet gas ≥50,000 ≥75 <3 >50

Dry gas ≥100,000 ≥90 <1 No liquid

API gravity of STO refers to the API gravity of sto produced at the surface facilities at standard conditions (289 K and 1 atm).

determine if a reservoir fluid is in the form of gas, liquid, or In this table, C7+ refers to all hydrocarbons having seven
a mixture of gas and liquid. These factors are (1) composi- or more carbon atoms; this group is called the heptane-plus
tion of reservoir fluid, (2) temperature, and (3) pressure. The fraction. C6 refers to a group of all hydrocarbons with six
most important characteristic of a reservoir fluid in addition carbon atoms (hexanes) that exist in the fluid. M7+ and SG7+
to specific gravity (or API gravity) is its gas-to-oil ratio (GOR), are the molecular weight and specific gravity, respectively,
which represents the amount of gas produced at standard at 15.5 °C (60 °F) for the C7+ fraction of the mixture. It
conditions in standard cubic feet (scf) to the amount of liquid should be noted that molecular weight and specific gravity
oil produced at the standard condition in stock tank barrels of the whole reservoir fluid are less than the corresponding
(stb). Other units of GOR and its calculation methods are values for the heptane-plus fraction. For example, for the
discussed in Chapters 1 and 10 of ASTM Manual 50 [1]. Res- crude oil sample in Table 2.2, the specific gravity of whole
ervoir fluids are generally categorized into four or five types, crude is 0.871, or an API gravity of 31. Details of such
the characteristics of which are given in Table 2.1. These five calculations are discussed in ASTM Manual 50 [1]. These
fluids in the direction of increasing GOR are black oil, volatile compositions have been determined from a recombination
oil, gas condensate, wet gas, and dry gas. of the compositions of the corresponding separator gas and
A natural gas is called dry gas if it does not produce stock tank liquid, which have been determined by various
any liquid hydrocarbons after the surface separator under analytical tools (i.e., gas chromatography, mass spectrom-
standard conditions. A natural gas that produces liquid etry, etc.). Composition of reservoir fluids varies with the
hydrocarbons after production at the surface facilities reservoir pressure and reservoir depth. In a producing oil
is called wet gas. The word “wet” refers to the presence field, the sulfur and amount of heavy compounds generally
of hydrocarbon liquids in a natural gas that condense at increase with production time. However, it is important
surface conditions. In dry gases no liquid hydrocarbon is to note that within an oil field, the concentration of light
formed at the surface conditions. Volatile oils have also hydrocarbons and the API gravity of the reservoir fluid
been called high-shrinkage crude oil and near-critical oils increase with the reservoir depth, whereas its sulfur and
because the reservoir temperature and pressure are very C7+ contents decrease with the depth [6]. The lumped C7+
close to the critical point of such oils, but the critical tem- fraction in fact is a mixture of many hydrocarbons up to C40
perature is always greater than the reservoir temperature or higher. As an example, the number of pure hydrocarbons
[1]. Gases and gas condensate fluids have critical tempera- from C5 to C9 detected by chromatography tools in a crude
tures that are less than the reservoir temperature. Black oil from North Sea reservoir fluids was 70 compounds.
oils contain heavier compounds; therefore, the API gravity Most recently, Mansoori has suggested that naturally found
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

of stock tank oil is generally lower than 40 and the GOR is hydrocarbon petroleums can be categorized into seven
less than 1000 scf/stb. The specifications given in Table 2.1 groups, including two semi-solid forms of tar sands and oil
for various reservoir fluids, especially at the boundaries shale [3]. The molecular weight distribution of these petro-
between different types, are somewhat arbitrary and may leum fluids is shown in Figure 2.5.
vary from one source to another. It is possible to have a Reservoir fluids from a producing well are introduced
reservoir fluid type with properties outside of the corre- to two- or three-stage separators that reduce the pressure
sponding limits given above. Determination of a type of and temperature of the stream to atmospheric pressure
reservoir fluid by the above rule of thumb on the basis of and temperature. The liquid leaving the last stage is called
the GOR, the API gravity of stock tank oil, or its color is stock tank oil (sto) and the gas released in various stages
not possible for all fluids. In general, oils produced from is called associated gas. The liquid oil after necessary field
wet gas, gas condensate, volatile oil, and black oil increase processing is called crude oil. The main factor in operation
in specific gravity (decrease in API gravity and quality) in and design of an oil-gas separator is to find the optimum
the same order. Liquids from black oils are viscous and operating conditions of temperature and pressure so that
black in color, whereas the liquids from gas condensates the amount of produced liquid (oil) is maximized. Such
or wet gases are clear and colorless. Volatile oils produce conditions can be determined through phase behavior cal-
brown with some red/green color liquid. Wet gas contains culations, which are discussed in detail in ASTM Manual
less methane than a dry gas but a larger fraction of C2–C6 50 [1]. Reservoir fluids from producing wells are mixed
components. The main difference between these reservoir with free water. The water is separated through gravita-
fluids is obviously found in their molecular composition. tional separators on the basis of the difference between
An example of the composition of different reservoir fluids densities of water and oil. The remaining water from crude
is given in Table 2.2 [1]. can be removed through dehydration processes. Another
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Chapter 2 n Feedstocks and Products of Crude Oil and Natural Gas Refineries 25

Table 2.2—Composition (mol %) and Properties of Various Reservoir Fluids and a Crude Oil [1]
Component Dry Gas (1) Wet Gas (2) Gas Condensate (3) Volatile Oil (4) Black Oil (5) Crude Oil (6)

CO2 3.70 0.00 0.18 1.19 0.09 0.00

N2 0.30 0.00 0.13 0.51 2.09 0.00

H2S 0.00 0.00 0.00 0.00 1.89 0.00

C1 96.00 82.28 61.92 45.21 29.18 0.00

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
C2 0.00 9.52 14.08 7.09 13.60 0.19

C3 0.00 4.64 8.35 4.61 9.20 1.88

iC4 0.00 0.64 0.97 1.69 0.95 0.62

nC4 0.00 0.96 3.41 2.81 4.30 3.92

iC5 0.00 0.35 0.84 1.55 1.38 2.11

nC5 0.00 0.29 1.48 2.01 2.60 4.46

C6 0.00 0.29 1.79 4.42 4.32 8.59

C7+ 0.00 1.01 6.35 28.91 30.40 78.23

100.00 100.00 100.00 100.00 100.00 100.00

GOR (scf/stb) … 69,917 4428 1011 855 …

M7+ … 113 143 190 209.8 266

SG7+ (at 15.5 °C) … 0.794 0.795 0.8142 0.844 0.895

API7+ 46.7 46.5 42.1 36.1 26.6

surface operation is the desalting process, which is neces- ous reasons during their production, transportation, and
sary to remove salt from crude oils. Separation of oil, gas, storage. These include but are not limited to acids, alcohols,
and water from each other and removal of water and salt aromatic hydrocarbons, detergents, and polymers. Fur-
from oil and any other process that occurs at the surface thermore, petroleum fluids often contain compounds that
are called surface production operations and are discussed result from the physical association with hydrocarbons;
in Chapter 11. these may include colloids, crystalline solids, flocs, and
In addition to the impurities (hetoroatoms and metals) slugs [3].
discussed earlier, some impurities may result from com- The crude oil produced from the atmospheric separa-
pounds that have been added to petroleum fluids for vari- tor has a composition different from the reservoir fluid

natural gas gas condensate light crude intermediate heavy oil tar sand oil shale
(NGL) crude

Figure 2.5—Various categories of natural gas and liquids naturally occurring in petroleum fluids and their approximate
hydrocarbon molecular weight distributions according to their carbon numbers [3,4].
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26 Petroleum Refining and Natural Gas Processing

obtained from a producing well. The light gases are sepa- separated with respect to their boiling points. Hydrocar-
rated, and crude oils usually have almost no methane and bons in a crude have boiling points ranging from –160 °C
a small C2–C3 content whereas its C7+ content is higher than (boiling point of methane) to more than 600 °C (1100 °F),
the original reservoir fluid. As an example, the composition which is the boiling point of the heaviest distillable com-
of a crude oil produced through a three-stage separator pounds in the crude oil. However, the carbon-carbon bond
from a reservoir fluid is also given in Table 2.2 in the last in paraffinic hydrocarbons breaks down at temperatures
column. Actually this crude is produced from a black oil near 350 °C (660 °F). This process is called cracking and
reservoir fluid, the composition of which is also given in it is undesirable during the distillation process because
Table 2.2 (column 5). it changes the chemical composition of the crude feed.
Two important characteristics of a crude oil that deter- For this reason, compounds having boiling points above
mine its quality are the API gravity (specific gravity) and 350 °C (660 °F), constituting the residuum fraction, are
sulfur content. Generally, a crude with an API gravity of removed from the bottom of the atmospheric distillation
less than 20 (specific gravity > 0.934) is called a heavy crude, column and sent to a vacuum distillation column. Because
and a crude with an API gravity of greater than 40 (specific by distillation it is not possible to completely separate the
gravity < 0.825) is called a light crude [1,5]. Crudes with an constituent compounds of the crude oil, a distillation col-
API gravity of less than 10 are considered as extra heavy oil, umn does not produce pure hydrocarbon streams. Instead,
such as bitumen. Similarly, if the sulfur content of a crude distillate f ractions are produced as defined according to
is less than 0.5 wt % it is called sweet oil. On the other the boiling point of the lightest and heaviest compounds in
hand, the term sour oil refers to crudes that have more than the mixtures of hydrocarbons. The lightest product of an
0.5 wt % sulfur. It should be noted that these ranges for the atmospheric column is a mixture of methane and ethane
gravity and sulfur content are relative and may vary from (but mainly ethane), which has a boiling range of –180 to
one source to another. Further classification of crude oils –80 °C (–260 to –40 °F) corresponding to the boiling points
will be discussed in Chapter 4. of methane and ethane, respectively. This mixture, referred
to as “fuel gas” in a refinery, is the lightest petroleum frac-
2.3 Refining Processes and Products tion. Fractions with a wider range of boiling points contain
from Crude Oil Refineries a greater number of hydrocarbons. All fractions from a
A crude oil produced after necessary field processing and distillation column have a known boiling range, except the
surface operations is transferred to a refinery for process- residuum, the upper boiling point of which is not usually
ing and conversion into various useful products. Petroleum known. The boiling points of the heaviest components in a
refining (or crude oil refining in more precise terms) has crude oil are not really known because many of them would
evolved from simple batch distillation in the late 19th cen- undergo cracking or other chemical reactions at tempera-
tury to today’s complex processing schemes in modern refin- tures lower than their boiling points. Identification of the
eries. Refining processes can be generally divided into three structure and determining the properties of the heaviest
major types: (1) separation, (2) conversion, and (3) finishing. compounds found in crude oils and petroleum residuum
Separation is a physical process that is carried out by still present a difficult challenge to researchers. Theoreti-
using different techniques to fractionate crude oil or its cally, it can be assumed that the boiling point of the heavi-
derivatives. The most important separation process is distil- est compound in a crude oil is infinity. Atmospheric residue
lation, which occurs in a distillation column to separate the contains compounds with carbon numbers greater than 25,
constituent compounds on the basis of differences in their whereas vacuum residue has compounds with a carbon
boiling points. Other major physical separation processes number greater than 50 (M > 800). Table 2.3 lists some
include absorption, stripping, and solvent extraction. In the petroleum fractions produced from distillation columns
gas plant of a refinery, absorption by a liquid solvent retains along with their boiling point ranges and applications. In
C3+ hydrocarbons from a gas mixture and allows methane this table, the boiling points and equivalent carbon number
and ethane to be sent overhead as fuel gas. The solvent is ranges are approximate and they may vary according to the
then regenerated in a stripping unit. The conversion pro- desirable properties of specific products. For example, the
cesses involve chemical changes that occur with hydrocar- light gas fraction consists mainly of a mixture of ethane,
bons in reactors. The purpose of such reactions is to change propane, and butane; however, some heavier compounds
the molecular weight and convert hydrocarbon compounds (C5+) may also exist in this fraction. The fraction is further
from one type to another. The most important reaction fractionated to obtain ethane (a fuel gas), propane, and
in modern refineries is cracking, which converts heavy butane (petroleum gases). The petroleum gases are lique-
hydrocarbons to lighter and more valuable hydrocarbons. fied under pressure to produce liquefied petroleum gas
Catalytic cracking and thermal cracking are commonly (LPG) that can be used as fuel for heating and cooking in
used for this purpose. Other types of reactions such as dwellings or as autogas [http://www.worldlpgas.com/]. In
reforming, isomerization, and alkylation are used to produce addition, butane may be separated from the gas mixture
high-octane-number gasoline. Finishing processes achieve to be used for improving the vapor pressure characteristics
the purification of various product streams by processes (volatility) of gasoline in cold weather. Petroleum fractions
such as desulfurization or acid treatment to remove impu- separated by distillation may undergo further processing to
rities and stabilize the fuels. Finishing processes that also produce the desired products. For example, gas oil may go
include blending ensure that the refinery products meet the through a cracking process to produce more gasoline. The
specifications dictated by performance characteristics and principal refinery processes are discussed in Chapter 5 of
environmental regulations [6–8]. this manual. Because distillation is not a perfect separation
Crude oil in a refinery upon the desalting process enters process, the initial and final boiling points for each frac-
the atmospheric distillation column where compounds are
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
tion are not exact and especially the endpoints represent
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Chapter 2 n Feedstocks and Products of Crude Oil and Natural Gas Refineries 27

Table 2.3—Some of the Petroleum Fractions Produced from Distillation Columns [1]
Approximate Boiling Range
Approximate
Petroleum Fraction Hydrocarbon Range °C °F

Light gases C2–C4 –90 to –1 –130 to 30

Gasoline (light and heavy) C4–C10 –1 to 200 30–390

Naphthas (light and heavy) C4–C11 –1 to 205 30–400

Jet fuel C9–C14 150–255 300–490

Kerosene C11–C14 205–255 400–490

Diesel fuel C11–C16 205–290 400–550

Light gas oil C14–C18 255–315 490–600

Heavy gas oil C18–C28 315–425 600–800

Wax C18–C36 315–500 600–930

Lubricating oil >C25 >400 >750

Vacuum gas oil C28–C55 425–600 800–1100

Residuum >C55 >600 >1100

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
approximate values. Fractions may be classified as nar- 2.3.1 Petroleum Fuel Products
row or wide depending on their boiling point range. As an The major petroleum fuel products of a refinery are LPG,
example, the fractionation of an Alaskan crude oil into vari- gasoline, jet fuel, diesel and heating oil, residual fuel oil, and
ous products by distillation is graphically shown in Figure petroleum coke as described below [1,7–10]. The specifica-
2.6. The weight and volume percentages for the products tions of these fuels are discussed in Chapter 4 of this manual.
are close to each other. It can be seen in Figure 2.6 that 1. LPGs are mainly used for domestic heating and cook-
more than 50 % of the crude is processed in the vacuum ing (50 %), industrial fuel (clean fuel requirement)
distillation unit. The vacuum residuum consists mainly of (15 %), feedstock for steam cracking (25 %), and as a
resin- and asphaltene-type compounds containing high- motor fuel (autogas) for spark ignition engines (10 %).
molecular-weight multiring aromatics. The vacuum resid- LPG is produced by crude oil refining or natural gas
uum may be further processed for upgrading or mixed with fractionation. The estimated world production in 2005
lighter petroleum fractions to obtain saleable products. was 250 million tons per year (≅8 million bbl/day) [10].
Distillation of a crude oil can also be performed in the LPG consists mainly of a mixture of propane (C3H8)
laboratory to divide the mixture into many narrow boiling and n-butane (C4H10), but it may also include ethane
point range fractions with a boiling range of approximately (C2H6), ethylene (C2H4), propylene (C3H6), butylene
10 °C. Such narrow range fractions are sometimes referred (C4H8), isobutane, and isobutylene in small concen-
to as petroleum cuts. When boiling points of all of the cuts trations. Propane, butane, or propane/butane mix-
in a crude are known, then the boiling point distribution tures can be liquefied at ambient temperature under
(distillation curve) of the whole crude can be obtained. In moderate pressure. LPGs are considered ideal fuels
a petroleum cut, hydrocarbons of various types are lumped because they can be transported and stored in liquid
together in four groups of paraffins (P), olefins (O), naph- form and used as a gas or a liquid. Propane can be safe-
thenes (N), and aromatics (A). For olefin-free petroleum ly used at ambient temperatures from approximately
cuts, the composition is represented by the PNA content. –40°C (–104°F) to 45°C (113°F), whereas butane can be
Crude oils are generally free of olefins. used at temperatures from 0°C (32°F) to approximately
As mentioned earlier, the petroleum fractions pre- 110°C (230°F) [8]. They have high energy density, low
sented in Table 2.3 are not the final products of a refinery. sulfur content, and they burn cleanly.
They go through further separation (physical), conversion LPGs have been used increasingly as auto fuel
(chemical), and finishing processes to achieve the product under the generic name “autogas.” The composition
specifications set by the market and government regula- of autogas varies depending on the prevailing ambient
tions. Through refining processes (discussed in Chapter 5), temperatures in the countries it is used. At moderate
the petroleum fractions shown in Table 2.3 are converted ambient temperatures, it consists of 60–70 % propane
to petroleum products. The terms “petroleum fraction,” and 30–40 % butane [9]. The advantages of using LPG
“petroleum cut,” and “petroleum product” are usually used compared with gasoline and diesel include lower fuel
interchangeably, but this is not appropriate because each and maintenance cost and lower engine emissions. See
term has a specific meaning that is different from the other Chapter 4 for specifications on autogas and variations
two. In general, the petroleum products that are obtained in specifications in different countries.
in a refinery can be divided into two groups— fuel prod- 2. Gasoline is perhaps one of the most important prod-
ucts and nonfuel products—as discussed in the following ucts of a refinery. In the United Kingdom it is referred
sections. to as petrol. Gasoline is obtained by blending various
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28 Petroleum Refining and Natural Gas Processing

Vacuum
50 Residuum
- 655

Vacuum
40 Gas Oil
Carbon Number

Boiling Point, °C
- 455
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

30
Heavy
Gas Oil
Atmospheric Distillation 46.9 %

- 345
20 Light
Gas Oil
- 205
Kerosene

10
Naphtha

Vacuum Distillation 53.1 %

- -90
0
0 20 40 60 80 100
Volume Percent

Light Gases Light Gasoline

Figure 2.6—Products and composition of Alaska crude oil [1].

streams obtained from different refinery operations, one-third of the refinery products in the United States,
including crude oil distillation, catalytic cracking, and whereas in July 2007 gasoline production was approxi-
catalytic reforming. It contains hydrocarbons from C4 mately 9.33 million bbl/day, or 37.5 % of total products
to C11 (molecular weight of ~100–110). It is used as a according to the API report.
fuel for cars with spark-ignition engines. Its main char- 3. Kerosene is a distillate fraction of crude oil that boils
acteristics include anti-nock (octane number), volatility between 150°C and 250°C and is primarily used for
(distillation data and vapor pressure), stability, and producing jet fuel to power gas turbine or jet engines.
density. The main evolution in gasoline production has To a much smaller extent, kerosene is used as fuel for
been the introduction of nonleaded gasoline (referred lighting and cooking, particularly in rural areas where
to as “unleaded gasoline,” which excludes using tetra- access to natural gas, LPG, and electricity is limited.
ethyl lead as an additive to increase the octane number) Jet fuel, which is also called “aviation turbine fuel,”
in many parts of the world and the use of reformulated is a premium fuel that has shown a faster increase in
gasoline (RFG) in the United States. The RFG has less demand than any petroleum fuel because of expanding
butane, less aromatics, and more oxygenates. Sulfur civil and military aviation. In 2007, an estimated con-
content of gasoline should not exceed 0.03 % by weight. sumption for jet fuel was 205 million t [10]. The main
Further properties and characteristics of gasoline will characteristics of jet fuel include sulfur content, cold
be discussed in Chapter 4. The U.S. gasoline demand resistance (more stringent performance for military jet
in 1964 was 4.4 million bbl/day and increased from 7.2 fuel), density, aromatics content, and ignition quality.
to 8.0 million bbl/day in a period of 7 years from 1991 ASTM and the International Air Transport Association
to 1998 [1]. In the 1990s, gasoline was approximately (IATA) have issued specifications for commercial (e.g.,
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Chapter 2 n Feedstocks and Products of Crude Oil and Natural Gas Refineries 29

Jet A, Jet A-1, the Russian TS-1) and military jet fuel benzene) and C2 to C4 olefins. In petrochemical plants,
(JP-8) that differ only in freezing point [9]. these feedstocks are used to produce plastics and res-
4. Diesel and heating oil are used for motor fuel and ins, pharmaceuticals, antifreeze agents, detergents,
domestic purposes. Diesel is obtained from fractional solvents, dyes, and agricultural chemicals such as
distillation of crude oil between 200°C and 350°C. fertilizers, pesticides, and herbicides. BTX and ethyl
The main characteristics are ignition (for diesel oil), benzene are produced in refineries [in fluid catalytic
volatility, viscosity, cold resistance, density, sulfur con- cracking (FCC) and catalytic reforming units] and in
tent (corrosion effects), and flash point (safety factor). petrochemical plants through reforming of naphtha.
There are basically three kinds of diesel fuel: No. 1, The C3 to C4 olefins are produced in FCC units, and C2
No. 2, and No. 4. Diesel No. 1 is for use in farm and and C3 olefins are produced by coking processes in a
city buses, whereas diesel No. 2 is for use in automo- refinery and steam cracking of naphtha or gas oils in
bile, truck, and railroad vehicles. Diesel No. 4 is for use petrochemical plants.
in railroad, marine, and stationary engines [9]. Diesel 3. Lubricants are composed of a main base stock obtained
fuels used in city buses have a lower endpoint, lower from dearomatized and dewaxed vacuum gas oils for
sulfur content, and higher cetane number. controlling the viscosity and freezing point and are
5. Residual fuel oil is used for industrial fuel, thermal pro- combined with additives to obtain the desired perfor-
duction of electricity, and motor fuel (low speed diesel mance characteristics. Among the most important char-
engines). Its main characteristics are viscosity (good acteristics of lubricants are thermal stability, viscosity,
atomization for burners), sulfur content (corrosion), and the viscosity index, which reflects the change of
stability (no decantation separation), cold resistance, viscosity with temperature. Aromatics are usually elim-
and flash point (for safety). Basically there are five types inated from lubricants to improve their viscosity index.
of fuel oils in commercial use: No. 1, No. 2, No. 4, No. 5, Lubricants consist mostly of isoparaffinic compounds.
and No. 6. Fuel oil No. 1 is used for stoves and farms, Additives used for lubricants include viscosity index
fuel oil No. 2 is for home heating uses, No. 4 is used for additives such as polyacrylates and olefin polymers,
light industrial uses, No. 5 is used for medium industrial antiwear additives (i.e., fatty esters), antioxidants (i.e.,
applications, and No. 6 is used for heavy industrial and alkylated aromatic amines), corrosion inhibitors (i.e.,
marine applications [9]. Fuel oil No. 1 has the lowest fatty acids), and antifoaming agents (i.e., polydimethyl-
density, boiling point, flash point, pour point, viscosity, siloxanes). Lubricating greases constitute another class
and sulfur content, whereas fuel oil No. 6 is the heaviest of lubricants that are semisolid. The specifications for
fuel oil, with high sulfur content and high viscosity. lubricants include viscosity index, freezing points, ani-
6. Petroleum coke, which is a solid byproduct obtained line point (indication of aromatic content), volatility,
from delayed coking or fluid coking of vacuum distilla- and carbon residue (indication of thermal stability).
tion residue, may be used as industrial fuel depending 4. Petroleum waxes are of two types: the paraffin waxes in
on its sulfur and metal contents [11]. It contains less petroleum distillates and the microcrystalline waxes in
than 1 %wt ash, but it needs to be burned in industrial petroleum residua. In some countries such as France,
furnaces with strict controls on emissions. Important paraffin waxes are simply called paraffins. Paraffin
properties of fuel coke include grindability, volatile waxes have high melting points; they are removed by
matter content, sulfur content, and nickel and vana- dewaxing of vacuum distillates to control the pour
dium contents. Nonfuel uses of petroleum coke are points of lubricating oil base stocks. Paraffin waxes are
described in the next section. mainly straight-chain alkanes (C18 to C36) with a very
small proportion of isoalkanes and cycloalkanes. Their
2.3.2 Nonfuel Petroleum Products freezing point is between 30 and 70 °C, and the average
The major nonfuel petroleum products include solvents, molecular weight is approximately 350. When pres-
naphthas, petrochemical feedstocks, lubricating oils, ent, aromatics appear only in trace quantities. Waxes
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

waxes, asphalts, and petroleum cokes [1,7–9,11]. Brief from petroleum residua (microcrystalline form) are
descriptions of the nonfuel products and their uses are less defined aliphatic mixtures of n-alkanes, isoalkanes,
given below. and cycloalkanes in various proportions. Their average
1. Solvents are light petroleum cuts in the C4–C14 range molecular weights are between 600 and 800, their car-
that have numerous applications in industry and bon number range is C30 to C60, and the freezing point
agriculture. For example, white spirits that have boil- range is 60–90 °C. Paraffin waxes (when completely
ing point ranges between 135 and 205 °C are used as dearomatized) have applications in food industry and
paint thinners. The main characteristics of solvents are food packaging. They are also used in the production of
volatility, purity, odor, and toxicity. Benzene, toluene, candles, polishes, cosmetics, and coatings [6,8]. Waxes
and xylenes (BTX) are used as solvents for glues and at an ordinary temperature of 25 °C are in solid states,
adhesives. Naphthas constitute a special category of although they contain some hydrocarbons in liquid
petroleum solvents with boiling ranges corresponding form. When melted, they have relatively low viscosity.
to those of white spirits. Similar to BTX, naphthas may 5. Asphalt is produced from vacuum distillation residues
be used as raw materials for producing petrochemical by solvent deasphalting. Asphalts contain nonvolatile
feedstocks, as described below. Therefore, naphthas high-molecular-weight polar aromatic compounds such
are considered to be industrial intermediates that are as asphaltenes and cannot be distilled even under very
subject to commercial specifications high vacuum conditions. In some countries asphalt is
2. Petrochemical feedstocks that are produced in the called bitumen, although this is not a strictly correct use
refinery include C6 to C8 aromatics (BTX and ethyl of the term bitumen. Asphaltic materials (containing
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30 Petroleum Refining and Natural Gas Processing

asphaltenes and resins) are used as binders for paving residue can be specified as sponge, or shot cokes,
the roads. The major properties of asphalt that deter- depending on their microstructure [11]. Sponge cokes
mine its quality include flash point (for safety), compo- that have low ash, low sulfur, and low metal contents
sition (wax content), viscosity, softening point, weather- can be used for making carbon anodes that are used
ing properties (resistance to oxidation or degradation), in electrolysis of alumina to manufacture aluminum.
specific gravity, and stability or chemical resistance. Shot cokes that are much harder than sponge cokes
6. There are some other products such as white oils (used have a niche application for producing titanium diox-
in pharmaceuticals or in the food industry), aromatic ide [11]. Delayed coking of FCC decant oils produces
extracts (used in the paint industry or the manufacture a special coke called “needle coke” that is used to pro-
of plastics), and coke (as a fuel or to produce carbon duce graphite electrodes for electric-arc furnaces for
electrodes for aluminum refining). Aromatic extracts recycling scrap iron and steel. Important properties of
are black materials composed essentially of condensed calcined needle cokes include density, ash content, and
PNAs and heterocyclic nitrogen or sulfur compounds, the coefficient of thermal expansion [11].
or both. Because of this highly aromatic structure, the In general, more than 2000 petroleum products within
extracts have a good solvent power. Petroleum cokes some 20 categories are produced in refineries in the United
produced by delayed coking of vacuum distillation States [6,8]. Some of these products obtained from a

Oil
Gas Commercial
Energy
Kerosene
Residue and Gas Oil Gas and Naphthas

Heavy Gasoline Car Fuel

Bitumen, Aviation
Lube Oil, etc, Fuel

n-alkanes n-alkyl carboxylic acids, e.g., acetic acid

Vinyl Chloride /alkenes
Petrochemical
Industry
Rubbers
Vinyl Acetate
HO(CH2)2OH C4 Butadiene
Hexane-
Ethylene -CH2- Adiponitrile diamine
Ethylene Oxide
Carbohydrate
Cyclohexane Cyclohexanone
Ethanol
CO H2
Adipic Acid

Ethyl
Chloride CH3X
Caprolactone
Oxalic HCOOH CH3OH
Acid Various Methyl Esters
e.g., Methyl Methacrylate
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Phenol

CH4 HCOOCH3 H3CCOOH CH3NH2 CH3(CH)nOH HCHO

Acetic Ethyl
Anhydride Acetate
HCON(CH3)2 HCONH2 C(CH2OH)4
Chloronated
Methanes
HCN H2NCO2(CO)NH

Fluoronated
Methanes
ClCN

Cyanuric Chloride
C2H2

Melamine1

Vinyl Vinyl
Chloride Acetate
Butyrolactam

HO(CH2)4OH Butyrolactone
NMP & NVP

Tetrahydrofuran

Figure 2.7—Some products produced from crude oil processing [12].

AST-MNL58-11-0801-002.indd 30 3/12/13 12:37 PM

Chapter 2 n Feedstocks and Products of Crude Oil and Natural Gas Refineries 31

typical crude oil are shown in Figure 2.7 as presented by as polyethylene, ethylene oxide, ethyl chloride, etha-
de Jong et al. [12]. In this figure, fuel products directly nolamine, ethylene glycol, acetaldehyde, styrene, ethyl
produced in refineries are marked in color, whereas many benzene, detergents, etc. Propylene is used to produce a
chemicals may be produced in the follow-up processes in a group of compounds through processes such as oxidation,
petrochemical plant. Blending techniques are used to make hydration, polymerization, and alkylation. These products
multiple products according to the desired properties or to include cumene, polymers, isopropyl alcohol, allyl chloride,
improve product quality. The product specifications must acetone, glycerin, epoxy resins, isobutanol, acetic acid,
satisfy customers’ requirements for good performance and nitroglycerin, etc.
government regulations for safety and environmental pro- Butanes in natural gas may be in the form of isobutene
tection. Therefore, to be able to plan refinery operations, or n-butane, which can be separated through a distillation
the availability of a set of product quality prediction meth- process. These components can be converted to products
ods is very important [1]. such as isobutylene, tert-butyl alcohol, butadiene, polybu-
tadiene, nylon, methyl ethyl ketone, synthetic resins, lube
2.4 Natural Gas and Its Products oil additives, tert-butyl phenol, etc., through dehydrogena-
The typical composition of natural gas is given in Table 2.2. tion, polymerization, and copolymerization processes.
Usually natural gases contain CO2 and H2S known as acid
gases, but the main components are methane, ethane, and 2.5 Biofuels
propane, although hydrocarbons as heavy as C11 may be Biofuels represent a group of fuels derived from biomateri-
present. Natural gases may also contain inert gases such als such as vegetable oil or biomass. A good example of a bio-
as nitrogen and helium. Pipeline gases containing mainly fuel is biodiesel, which is a cleaner fuel than petrodiesel and
nitrogen, helium, C1, C2, and C3 in liquefied form are called can be produced from renewable sources such as vegetable
LNG. The liquefied form of gases C2, C3, and C4 is called oil, palm oil, cooking oil, or animal fat. These oils undergo
LPG. Pentanes and heavier including isobutane can be a process called transesterification, in which they react with
separated from natural gas as natural gasoline. Natural gas an alcohol such as methanol or ethanol with sodium hydrox-
liquids (NGLs) and light and heavy naphthas may also be ide or potassium hydroxide as catalyst [13–16]. Transesterifi-
separated naturally from natural gas. At normal pressure cation converts fats and oils (triglycerides) into alkylesters of
conditions, only C5 and heavier components are in liquid fatty acids that have similar properties to those of petroleum
form. Methane needs to be refrigerated to –259°F to have it diesel. The process produces large quantities of glycerol as
as liquid. For storage of natural gas at normal temperatures a byproduct. Biodiesel does not contain any sulfur or aro-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

(above boiling point), it is necessary to compress it, which matics. Therefore, in comparison to petroleum diesel, the
is known as compressed natural gas (CNG). Liquid mixtures combustion of biodiesel results in a reduction in unburned
of C3 and C4 are ideal fuel for many applications. They are hydrocarbons, carbon monoxide, and particulate matter
stable, high-energy content, relatively low sulfur, and clean emissions. Because it has a higher flash point it is safer to
burning fuels that can be transported as liquid and used as store and to handle [15–17]. Biodiesel can be used in its pure
liquid or gas. LPG can be produced from natural gas and form (B100) or in blends with petroleum diesel in a wide
crude oil. LPG is also a preferred feedstock for petrochemi- range of concentrations (e.g., B2, B5, B20) in diesel engines.
cals, gas cracking, and plastics. The first commercial use Another group of biofuels comprises bioalcohols,
of LPG from crude oil or natural gas was in 1912. Propane which are biologically produced alcohols. The most com-
used in LPG is not suitable for gasoline (it is very volatile) or monly used bioalcohols are ethanol, propanol, and butanol.
for use in natural gas (heavy component in natural gas pipe- Butanol can be used directly in spark-ignition (gasoline)
line), so its best application is in LPG. The ratio of C3–C4 in engines without any alteration. Butanol can produce more
LPG mainly depends on the temperature because at high energy than ethanol and is less corrosive because it is less
temperatures (summer) more C4 and at low temperatures soluble in water. However, ethanol is the most commonly
(winter) more C3 is used in the mixture. Tanks containing used biofuel in the world and in particular in Brazil. Etha-
LPG should never be filled with liquids to allow space for nol can also be mixed with gasoline at any ratio, but use of
vapors and volume expansion for safety reasons [8]. 15 % bioethanol in gasoline (marked by E15) is common.
Natural gas and NGLs are also the main feedstocks for Mixtures of gasoline and ethanol produce less pollution
petrochemical plants. Through absorption processes, H2S than gasoline upon combustion, especially in cold winters
can be separated from natural gas, and upon oxidation of and high altitudes. However, ethanol has a lower heating
H2S sulfur can be produced. Through distillation/extraction value than gasoline [13].
processes, components such as C2, C3, C4, and heavier com- Other types of biofuels include biogas and solid biofu-
pounds are separated. Methane as the main component of els. Biogas is produced when organic material is anaerobi-
natural gas can be used through processes such as reform- cally digested by anaerobes. Biogas consists of methane,
ing and oxidation to produce a group of chemicals such and landfill gas is created in landfills because of natural
as CO2, hydrogen, ammonia,, methyl chloride, acetylene, anaerobic digestion. Charcoal and wood are examples of
methanol, nitric acid, urea, acrylonitrile, vinyl chloride, solid biofuels. The combined processes of gasification,
ethanol, propanol, butanol, formaldehyde, pharmaceuticals combustion, and pyrolyis can produce syngas, which is a
and feeds to pharmaceutical industries, carbon tetrachlo- biofuel. This syngas can be directly burned in internal com-
ride, acetaldehyde, vinyl resins, etc. bustion engines. Syngas can be used to create hydrogen and
The next main components of natural gas are eth- methanol. Syngas can be transformed to a synthetic petro-
ane and propane. These components can be converted leum substitute using the Fischer–Tropsch process. Finally,
to ethylene and propylene through cracking processes. a third-generation biofuel is produced from algae, which is
Ethylene can be used to produce many products such called “oilage” [13].
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32 Petroleum Refining and Natural Gas Processing

References [11] Eser, S., and Andresen, J., “Properties of Fuels, Petroleum
[1] Riazi, M.R., “Characterization and Properties of Petroleum Pitch, Petroleum Coke, and Carbon Materials,” in Fuels and
Fractions, MNL50,” ASTM International, West Conshohock- Lubricants Handbook: Technology, Properties, Performance,
en, PA, 2005. and Testing, MNL37, G.E. Totten, R.J. Shah, and S.R. West-
brook, Eds., ASTM International, West Conshohocken, PA,
[2] “IUPAC: International Union of Pure and Applied Chemistry
2003, pp. 757–786.
(IUPAC),” http://www.iupac.org (accessed July 7, 2009).
[12] de Jong, E., van Ree R., van Tuil, R., and Elbersen, W.,
[3] Mansoori, G.A., “A Unified Perspective on the Phase Behavior
Biorefineries for the Chemical Industry—A Dutch Point of
of Petroleum Fluids,” Int. J. Oil, Gas Coal Technol., Vol. 2,
View, A Joint Research Report from Agrotechnology and Food
2009, pp. 141–167.
Innovations, Wageningen, The Netherlands and the Energy
[4] Riazi, M.R., “Energy, Economy, Environment and Sustainable Research Centre of the Netherlands (ECN)—Biomass Depart-
Development in the Middle East and North Africa,” Int. J. Oil, ment, Petten, The Netherlands, http://www.biorefinery.nl/
Gas, Coal Technol., Vol. 3, 2010, pp. 301–345. fileadmin/biorefinery/docs/biorefineries_for_the_chemical_
[5] Altagelt, K.H., and Boduszynski, M.M., Composition and industry_a_dutch_point_of_view.pdf (accessed July 2009).
Analysis of Heavy Petroleum Fractions, Marcel Dekker, New [13] “Biofuels: The Fuel of the Future,” http://biofuel.org
York, 1994. .uk/types-of-biofuel.html (accessed July 7, 2009).
[6] Speight, J.G., The Chemistry and Technology of Petroleum, 3rd [14] Srivastava, A., and Prasad, R., “Triglycerides-Based Diesel
ed., Marcel Dekker, New York, 1998. Fuels,” Renew. Sustain. Energy Rev., Vol. 4, 2000, pp. 111–133.
[7] Wauquier, J.-P., Petroleum Refining. Vol. 1 Crude Oil. Petro-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

[15] “Natural Resources Canada: Biodiesel,” http://oee

leum Products. Process Flowsheets, Editions Technip, Paris, .nrcan.gc.ca/transportation/alternative-fuels/index.cfm?attr=8
1995. (accessed July 7, 2009).
[8] Gary, J.H., Handwerk, G.E., and Kaiser, M.J., Petroleum Refin- [16] Meher, L.C., Vidya Sagar, D., and Naik, S.N., ”Technical
ing, Technology and Economics, 5th ed., Marcel Dekker, New Aspects of Biodiesel Production by Transesterification—A
York, 2007. Review,” Renew. Sustain. Energy Rev., Vol. 10, 2006, pp.
[9] Totten, G.E., Westbrook, S.R., and Shah, R.J., Fuels and Lubri- 248–268.
cants Handbook: Technology, Properties and Testing, MNL37, [17] Morf, O, “BIODIESEL: A Guide for Policy Makers and
ASTM International, West Conshohocken, PA, 2003. Enthusiasts,” National Agricultural and Environmental
[10] Parkash, S., Petroleum Fuels Manufacturing Handbook, Forum, Siddharthanagar, Bhairahawa, Nepal, http://www
McGraw-Hill, New York, 2010. .naef-nepal.org (accessed July 7, 2009).

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3
Worldwide Statistical Data on Proven
Reserves, Production, and Refining Capacities
of Crude Oil and Natural Gas
M.R. Riazi1, Mohan S. Rana2, and José Luis Peña Díez3

3.1 Introduction elected a Russian as its director [8]. The lifetime of gas
The world’s energy is produced from various sources, reserves at present rates is much higher than oil reserves, as
including oil, gas, coal, and nuclear and renewable sources shown in Table 3.2; however, as production and consump-
such as solar, wind, water, biomass, and geothermal tion of natural gas increases, the lifetime of such reserves is
sources. Oil, gas, and coal are fossil-type hydrocarbons expected to decrease in present scenarios. The rate of con-
that are not renewable and currently make up more than sumption of natural gas in non–Organization for Economic
80 % of the world’s energy consumption. Oil and gas may Cooperation and Development (OECD) countries (mainly
be produced as different naturally occurring hydrocarbon from Asia) in the next few decades is expected to be higher
fluids from natural gas to bitumen and shale oil as shown than OECD countries according to the Energy Information
in Figure 3.1 for seven classifications [1]. Heavier fluids Administration (EIA).
contain compounds with higher carbon number and higher Hydrocarbon production has been traditionally based
carbon-to-hydrogen ratios, which means lower quality for on the most accessible fluids (conventional oil and gas),
the oil and less desirable feedstock in terms of production whereas resources difficult to develop by technical or eco-
and processing costs. nomical reasons have been usually referenced as “uncon-
Major oil and gas fields are located largely in the Mid- ventional resources.” Heavy oils (having an API gravity
dle East, as shown in Figure 3.2 [2,3]. Approximately 60 % < 20) or extra-heavy oil (with API gravity < 10) together
of the world’s oil reserves are located in the Middle East, as with sand oils and shale oil form the group of unconven-
shown in Table 3.1. In fact, Saudi Arabia, Iran, Kuwait, and tional oils. Venezuela, Canada, and Russia are known to
Iraq from the Middle East along with Venezuela from South have the largest worldwide heavy-oil resources. Current
America formed the Organization of Petroleum Exporting production of unconventional oil is much lower than con-
Countries, known as OPEC, in 1960. Later, nine other oil- ventional types; however, as the price of oil increases, the
producing countries joined OPEC, and these countries are production and processing of unconventional oils become
now major world oil producers. This trend will continue, more economical and feasible. On the other hand, tight
according to the recent International Energy Agency (IEA) gas, shale gas, and coal-bed methane stand as the main
reference scenario, in which OPEC will account for 54 % short-term unconventional gas resources. The geographi-
of the total world’s oil supply by 2030, compared with 45 % cal distribution is dispersed, with large resources in North
today [4]. Middle Eastern producers will supply 50 % of America and China. The case of shale gas is particularly
U.S. oil imports, 50 % of Europe’s, 80 % of China’s, and relevant because the development of U.S. resources is play-
90 % of Japan’s oil imports. Reservoir lifetime (ratio of ing a significant role in changing the global gas markets.
proven reserves to production rate) of non-OPEC produc- Crude-oil availability has been a topic of discussion dur-

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
ers is much lower than OPEC’s: approximately 15 years for ing the last decades, producing much literature supporting
non-OPEC and more than 70 years for OPEC-producing conflicting positions. Although the discussion is still alive,
countries, as shown in Table 3.1 [4,5]. with added uncertainty provided by the recent economic
World natural gas reserves have traditionally trended downturn, it seems there is a major confidence in hydro-
upward, and the beginning of 2009 showed that total world carbon availability, with the challenge being to increase the
natural gas reserves stood at 6254 trillion ft3, of which production from brown fields through enhanced recovery
Middle East shares are 2549 trillion ft3 [6,7]. In 2001, an processes and make economically feasible the exploitation
organization of natural-gas-exporting countries informally of more difficult reservoirs (especially unconventional). As
known as the Gas OPEC was formed by Russia, Qatar, becoming generally agreed, it is “the end of easy oil” [9,10].
and Iran. The members now also include Algeria, Bolivia, The oil refining industry is presently at a critical junc-
Egypt, Equatorial Guinea, Iran, Libya, Qatar, Nigeria, Rus- ture because of the variations in the crude-oil scenario and
sia, Trinidad and Tobago, and Venezuela as well as Kazakh- emission regulations. Between 2000 and 2009, the industry
stan and Norway as observers. This organization recently witnessed capacity variation and product quality challenges

1
Kuwait University, Kuwait
2
Kuwait Institute for Scientific Research, Kuwait
3
Repsol, Madrid, Spain
33
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34 Petroleum Refining and Natural Gas Processing

QDWXUDOJDV JDVFRQGHQVDWH OLJKWFUXGH LQWHUPHGLDWH KHDY\RLO WDUVDQG RLOVKDOH

1*/ FUXGH

Figure 3.1—Normal condition of the seven naturally occurring petroleum fluids [1].
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 3.2—Major oil and gas giant fields in the Middle East [2,3].

with disparities in demand. The focus of the oil industry has regions, Asia, Central and South America, and the Middle
been on crude-oil production, but the inadequacy of refin- East will be known as an explosion region, which will lead
ing capacity has become the main industry concern. The the movement of oil products market. On the supply side,
global trend indicated that the world oil refining industry the crude-oil shares in the total primary energy supply will
has to face several challenges for demand and supply. On remain high, at least during the next decade. The conven-
the demand side, the growing activity of the transport sectional crude-oil supply will decrease, but heavy- and extra-
tor will involve increasing quantities of cleaner liquid fuels heavy crude oil and tar sands supply will be increased.
as motor gasoline and diesel fuels. In this regard, North In any case and independently from the crude-oil quality,
American and European demand will tend to reduce for demand and supply in all petroleum streams will have
gasoline whereas diesel will remain unchanged or slightly to meet environmental constraints to limit the emissions
increased. Contrary to North American and European specifications.
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Chapter 3 n Worldwide Statistical Data 35

same time [13]. In 2002, total energy consumption in the

Table 3.1—Proven Conventional Oil United States was 97.4 quads [14], almost 24 % of the world
Reserves by Regions at the End of 2008 demand. According to the EIA [6], the international energy
in Billion Barrels of Oil [4] outlook for global energy demand in 2006 was 472 quadril-
Region 109 Barrels Percent R/Pa lion Btu. From an energy point of view, 1 quadrillion (1015)
Btu energy can be produced by approximately 45 million
Middle East 754.1 59.9 78.6
tons of coal, or 1 trillion ft3 of natural gas, or 170 million bbl
Europe and Eurasia 142.2 11.3 22.1 of crude oil. The evolution of world energy consumption
during the last 50 years is shown in Figure 3.3.
Africa 125.6 10.0 33.4
There is a strong correlation between economic devel-
South and Central America 123.2 9.8 50.3 opment and energy consumption, as shown in Figure 3.4.
North America 70.9 5.6 14.8 When this relationship is analyzed individually for each
country, major differences in specific energy consumption
Asia-Pacific 42.0 3.3 14.5 become visible (Figure 3.5), although the general trend
World (total) 1258.0 100.0 42.0 continues to be valid [15]. These differences are the conse-
quence of many factors, from energy efficiency to domestic
OPEC 955.8 76.0 71.1 demand, with strong climate dependence. Energy con-
Non-OPEC 174.4 13.9 14.8 sumption per capita has significantly increased during the
last decades in developing countries, as opposed to OECD
Former Soviet Union 127.8 10.1 27.2
countries, in which stabilization has taken place [16], as
World (total) 1258.0 100.0 42.0 presented in Figure 3.6. Although there is a possibility for
these values being modified in the future by the progressive
R/P, reserves-to-production ratio.
a
implementation of laws and carbon policies with a focus
on energy efficiency, they provide a basis for understanding
the present energy consumption distribution and the dif-
Table 3.2—Proven Conventional Gas ferences appearing in the structure of the energy portfolio
Reserves by Regions at the End of 2008 share for different regions.
in Trillion Cubic Feet [4] The use of diverse energy fuels has changed over time.
Region TCFa Percent R/Pb Coal surpassed wood’s usage, the main energy source over
most of human history, in the late 19th century and was, in
Middle East 2680.9 41.0 –
turn, overtaken by oil, another fossil fuel. In the first half of
Europe and Eurasia 2220.8 34.0 57.8 the 20th century, oil began to replace coal, and by the 1970s
oil had become the leader in world energy supply contribu-
Africa 517.5 7.9 68.2
tion. Figure 3.7 shows the evolution of the contribution of
South and Central America 258.2 4.0 46.0 different sources to energy production in recent decades.
Fossil fuels are the most attractive energy sources in
North America 313.1 4.8 10.9
terms of efficiency: they are highly concentrated, which
Asia-Pacific 543.5 8.3 37.4 enables large amounts of energy to be stored in relatively
World (total) 6534.0 100.0 60.4 small volumes, and they are relatively easy to handle and
distribute. Oil still provides more than one third of the world
TCF, trillion cubic feet; bR/P, reserves-to-production ratio.
a
energy consumption, but projections indicate that this pro-
portion will decrease in the coming decades. According to
EIA, production of oil in this decade was nearly constant and

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
3.2 Share of Petroleum and Natural Gas less than 80,000 bbl/day, in which OPEC produced approxi-
in World’s Energy Consumption mately one third of this amount. Natural gas started to make
This section summarizes the share of oil and gas in provid- a significant contribution in the second half of the 20th cen-
ing energy in the past and future for different regions and tury and it is gaining a key role in energy global markets in
applications. Factors affecting increase in energy consump- the beginning of this century. The contributions from other
tion and share of other sources of energy such as renew- energies (mainly nuclear and hydro) continue to be minor.
able, coal, and nuclear factors are also reviewed. Some The structure of energy mix in energy consumption
common unit conversions for various forms of energy used shows significant changes when comparing different areas.
in this chapter are given in Table 3.3 [11]. Table 3.4 summarizes the share of total energy consump-
tion by fuels in 2007 as published by several institutions.
3.2.1 Energy Consumption Primary energy consumption in various regions and the
The analysis of current world energy needs is critical world based on data from BP is also shown in Figure 3.8
to the understanding of future energy scenarios and [11]. These data are represented in Figure 3.9, organized as
the relationship with fossil fuel reserves. World energy energy charts to emphasize the geographical differences in
needs have increased exponentially during the last century, their main source of energy. From this information, several
approximately 4 times the population growth in the same conclusions can be outlined:
period. On the basis of the fossil fuel availability, the world • Fossil fuels (oil, gas, and coal) represent approximately
population almost quadrupled from 1.6 billion in 1900 to 90 % of the world’s energy consumption, with oil being
6.1 billion in 2000 [12], whereas energy consumption grew the main energy source, and gas and coal with similar
from approximately 21 quads to over 400 quads in the contributions.
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36 Petroleum Refining and Natural Gas Processing

Table 3.3—Approximate Values of Energy Equivalency for Various Fuels

1 ft (standard cubic foot, SCF) of gas is equivalent to 1000 Btu or 1000 SCF ≈ 1 MMBtu
3

1 bbl of oil is equivalent to 5500 SCF of gas

1 bbl of oil is equivalent to 0.158987 (~0.159) m3, or approximately 159 L
1 MMBtu is equivalent to 0.17 bbl (or ~23 kg ) of crude oila
1 Quadrillion (1015) Btu energy is approximately equivalent to 45 million t of coal
1 Quadrillion (1015) Btu energy is approximately equivalent to 1 trillion ft3 of natural gas or 170 million bbl of crude oil
1 t (1000 kg) of coal gives approximately 28 MMBtu of heat
1 Mtoe is equivalent to 1 million t of oil equivalent = 41.87 × 1015 J = 3.97 × 1013 Btua
1 toe is 1 ton of oil equivalent, which is 7.14 bbl of oil equivalenta
1 MMBtu is equivalent to 36 kg of coal
1 bbl of crude oil is approximately 5500 ft3 (0.0055 MMcf) gas ≈ 0.21 t of coal
1 t oil is equivalent to 1.5–1.8t of coal (equivalent heating value)
1 gal of gasoline gives approximately 0.11 MMBtu
Heating value of ethanol (a biofuel) is approximately two thirds the heating value of gasoline
a
The value depends on the type and gravity of crude oil and varies from one source to another and could be 1 MMBtu = 23–25 kg oil equivalent.

Ă ď

%LOOLRQ%DUUHOV2LO(TXLYDOHQW

4XDGULOOLRQ%WX

<HDU <HDU

Figure 3.3—World energy consumption and projections to 2030: (a) in quadrillion Btu energy and (b) in billion barrels of oil
equivalent based on data from EIA [13]. Data from 1980 to 2006 are history and 2007 to 2030 are projections.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 3.4—World specific energy consumption per capita in 2008 (ton of oil equivalent) [4].
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Chapter 3 n Worldwide Statistical Data 37

Figure 3.5—Relation between development and energy consumption for selected countries. Source: [15] with figure from Frank
van Mierlo and data from 2006 (IEA).

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Figure 3.6—Primary energy consumption per capita, 1965–2005 [4]. Population data from the United Nations [12].

(QHUJ\(- • In the United States and the European Union (EU),

1XFOHDU
consumption distribution is similar to the average

+\GUR world data, with oil and gas as two of the major shares.
*DV In the United States, coal has more participation in the
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energy map (23 % vs. 18 % in the EU), whereas in the
:RRG EU, nuclear and renewable shares have more presence
than in the United States.
• The energy mix in the Middle East is mainly based on
oil and gas, with minor contributions from the rest.
• Russian dependence on gas is significant (>50 %) com-
pared with the other areas.
• In the Asia-Pacific area (China and India), approxi-
mately 50 % of the total energy consumption is from
coal, whereas natural gas and nuclear sources have
<HDU
minor contributions.
Figure 3.7—Contribution of different sources to energy pro- • Africa presents a totally different distribution, with a
duction in past years [17]. major dependence on coal and biomass.
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38 Petroleum Refining and Natural Gas Processing

Table 3.4—Share of Total Energy Consumption by Fuel in 2007

Energy Consumption
Source Oil (%) Gas (%) Coal (%) Nuclear (%) Renewablesa (%) (106 toe)

World [18] 34.1 20.9 26.5 5.9 12.6 12,013

United States [19] 40.7 23.7 22.7 8.4 4.5 2343

EU [20] 36.2 23.9 18.4 12.6 8.8 1967

Russia [20] 19.7 54.4 15.2 6.3 4.4 672

China [20] 18.2 3.1 65.6 0.8 12.3 1969

India [20] 23.7 5.6 40.8 0.7 29.3 595

Middle East [20] 52.2 45.3 1.8 0.0 0.7 552

Africa [20] 21.1 13.1 16.9 0.5 48.4 629

a
Including hydro, biomass, and other renewables.

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Figure 3.8—Primary energy consumption: (a) per region and (b) per fuel [11].

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Figure 3.9—Energy dependence charts for different areas [13–15].

• Nuclear contribution, although minor, is only signifi- in Figure 3.10, according to EIA, for recent available
cant in OECD countries, but it does not reach repre- data [21]. Oil contributions in 2008 were 37 % of total
sentative contributions in South and Central America, energy, and oil is mainly used in the transportation sec-
Africa, and the Middle East. tor (94 %). Natural gas contributes 24 % of total energy
A strong relationship also exists between the source and is used mainly in residential and commercial appli-
of energy and its application. The approximate primary cations. Coal and nuclear energy are exclusively used
energy consumption by source and sector is represented
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for electric power generation. This distribution does not
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Chapter 3 n Worldwide Statistical Data 39

change significantly when compared with most devel- demand that may persist for the short term, although all
oped countries. of the scenarios provide similar quick resumption and
The present consumption scenario is the result of a long-term upward trends [23]. Increase in the energy con-
period of cheap and easily available fossil fuels with a sumption will very much depend on how these scenarios
strong interrelationship among development, population about world economy recovery become a reality. For three
growth, and energy resources [22]. The validity of this sce- economy cases, energy consumption through 2030 is shown
nario in the future will depend on the expected country and in Figure 3.11. Most of the energy consumption increase is
individual consumption trends as well as energy availability due to energy consumption in non-OECD countries. For the
under similar conditions. United States and OECD countries, the increase in energy
consumption by 2030 is moderate as given by the EIA Inter-
3.2.2 Future Consumption Trends national Energy Outlook [13]. The rapid growth in energy
According to EIA [13], the international energy outlook for demand for this period is expected to be for non-OECD
global energy demand in 2006 was 472 quadrillion Btu and nations, while the energy demand increase for the same
will increase to 552 quadrillion Btu in 2015 and then to 678 period would be 73 % (Figure 3.12). This is mainly related
quadrillion Btu in 2030, with an increase of 44 % in 25 years to faster economic growth rate for nations outside of the
(average annual growth 1.5 %) as shown in Figure 3.3. The OECD, which is expected to have a gross domestic product
scenarios proposed by alternative sources provide similar (GDP) of approximately 5 % in comparison with 2 % GDP
annual growths. The IEA reference scenario [18] projects growth per year for the OECD countries [11]. Under the
a world primary energy demand yearly increase by 1.5 % reference EIA scenario (1.5 % average annual consumption
between 2007 and 2030, from 12,000 million tons of oil equiv- growth rate), OECD countries would have a 0.6 % annual
alent (Mtoe) to 16,800 Mtoe, with an overall increase of 40 %. increase, whereas for non-OECD countries the annual
The first decrease in energy consumption in decades growth rate would be 2.3 %, 4 times higher.
came in 2009 because of the world economic downturn. Energy efficiency is another important factor to con-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

The economic slowdown is creating a real decline in energy sider when analyzing future energy consumption scenarios.
Although economic growth in developed countries has
reduced the required energy consumption, this improvement
has not been sufficient to prevent total final energy needs
from rising, as presented in Figure 3.6a. Most of the sectors
have succeeded in reducing energy consumption per capita
except in private household consumption, mostly because
of greater ownership of electrical equipment.
shows the trend during the last decade in the EU [24], with
significant decreases in energy intensity in all sectors except
household, where stabilization has occurred during the last
few years. This trend is expected to continue, and energy
conservation will probably start to play a role in household
consumption on the basis of higher environmental pressures
and the implementation of directives for minimum energy
performance standards. Significant progress in energy sav-
ings could be achieved with minor personal lifestyle changes.
World economy and rate of energy consumption also
depend on the oil and energy prices in general. Every oil
Figure 3.10—U.S. primary energy consumption by source and price hike is usually followed by a decrease in demand,
sector [21]. which in turn causes oil prices to decline. Oil price

Figure 3.11—World marketed energy consumption in three Figure 3.12—World marketed energy consumption: OECD vs.
economic growth cases and projections to 2030 [13]. non-OECD countries 1980–2030 [13].
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40 Petroleum Refining and Natural Gas Processing

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 3.13—Index of final energy intensity and energy intensity by sector, EU-27 [24].

reached a peak value of $148/bbl in July 2008, which was energy consumption by different fuels or projections to
related to the world economic crisis. However, during the 2030, as shown in Figure 3.15 [13]. The contribution of vari-
following 2 years, the oil market did not respond to the ous sources of energy for electricity production from 2006
price variations, and the price collapse in 2009 did not to 2030 according to the EIA is shown in Figure 3.16 [13].
stimulate demand. The oil market is not a traditional sup- The share of oil for electricity generation almost remains
ply/demand market; it is partly driven by external factors constant, whereas shares of renewable sources, natural gas,
and has limited flexibility [15]. Economic downturn, war and coal will increase.
and political tension in the oil-producing countries, and However, as projections vary from one source to
world population growth also contribute to tensions in another, other sources expect major changes in the world
oil prices. Figure 3.14 shows projections of oil prices until energy distribution during the rest of the century, with oil
2030 for three economic growth cases. The impact of the demand beginning to decrease by 2020; for natural gas,
current economic crisis on energy consumption seems to the peak in demand is reached around 2050 and decreases
be limited in time according to recent data [23], although after that date, as shown in Figure 3.17 [17]. On the basis
some supply challenges are expected, as seen later in this of these sources, by the end of the century contribution of
chapter. This situation, together with the higher pressure renewable sources of energy such as solar, wind, or bio-
imposed by new greenhouse gas (GHG) legislations, will mass may be higher than that of oil and gas. According to
probably increase the need for alternative energies to cover other sources [e.g., the German Advisory Council on Global
this increasing gap. Change (GACGC), Berlin], nuclear energy contributes
The previous factors will have an impact in the structure only slightly to total energy production and consumption
of energy mix, especially in the long term. The base scenario whereas solar energy is the biggest source for energy pro-
does not identify major changes in the distribution of world duction by 2050–2100, as shown in Figure 3.18 [25].

Figure 3.14—World oil prices in three economic growth cases Figure 3.15—World marketed energy use by fuel type and
[13]. projections to 2030 [13].
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Chapter 3 n Worldwide Statistical Data 41

(QHUJ\(-

:DVWH
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1XFOHDU

+\GUR
*DV
2LO
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:RRG

<HDU

Figure 3.17—Anticipated contribution of different sources to

energy production in the 21st century [17].
Figure 3.16—World electricity generation by fuel, 2006–2030
[13].

1,600 Geothermal
Other
renewables
1,400 Solar thermal
(heat only)
Primary energy use (EJ/a)

1,200

Solar power
1,000 (photovoltaics
and solar thermal
generation)
800

Wind
600
Biomass
(advanced)
Biomass
400 (fractional)
Hydroelectricity
Nuclear power
200
Gas
Coal
0 Oil
2000 2010 2020 2030 2040 2050 2100
Year
Figure 3.18—Projected energy use by 2050 and 2100 [17].

3.3 Petroleum and Natural Gas Reserves traded oil and gas companies. The main focus is recov-
3.3.1 Hydrocarbon Resource Classification erable (and hence valuable) fluids.
Within this chapter, an updated vision about the amount • Government and industry reporting (Norway, Former
of fossil hydrocarbons remaining under the surface will Soviet Union, China): In this case, the focus of the
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

be presented. How these resources are measured and clas- agencies is the future energy availability for each coun-
sified is a challenge in itself. Although based on similar try. Apart from recoverable fluids, the probability of
basic principles taking into account the certainty about the geological-based success is also considered, in some
existence of the resources and the considerations about the cases for large geographical areas not limited to coun-
extraction feasibility, there are many different definitions at tries [U.S. Geological Survey (USGS)].
technical and legal levels. These differences make analyzing • Technical standards [Society of Petroleum Engineers
data provided by different sources challenging, and this has (SPE), United Nations Framework Classification
been one of the possible causes of past confusions when (UNFC)]: These are independent standards presented
comparing scenarios on the basis of published data. to promote international consistency in total resource
The classification can typically be categorized into assessment processes and terminology. Although SPE
three main groups [26]: classification applies to oil and gas, UNFC extends to
• Security disclosures [U.S. Securities and Exchange Com- other energy minerals.
mission (SEC), Canadian Securities Administrators There have been many efforts to achieve a harmonized
(CSA), UK Sorp]: These agencies provide financial classification, pointing out the benefits of providing a
accounting rules to provide reserves information to single definition for the different stakeholders [27]. Some
investors to compare the performance of publicly of the most important technical associations related to oil
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42 Petroleum Refining and Natural Gas Processing

and gas, the SPE, the World Petroleum Council (WPC), the reserves have been repeatedly quoted as being sufficient to
American Association of Petroleum Geologists (AAPG) and satisfy future energy demand.
the Society of Petroleum Evaluation Engineers (SPEE), Another classification commonly used, following a dif-
proposed in 2007 a unified guideline on resource definition ferent approach, divides resources into conventional and
and classification called the Petroleum Resources Manage- unconventional. These terms are in wide usage, but they
ment System (PRMS) [28]. lack a standard definition, adding additional deterministic
This system classifies resources and reserves according criteria to the proved reserves. SPE established the limits
to the level of uncertainty about the volume of recoverable between the two categories according to parameters such
fluids and the probability to exploit them economically as localized or continuous-type deposits, hydrodynamic
(Figure 3.19). The first classification attends to the reser- influences, specialized extraction technologies, or surface
voir discovery, defining resources as “prospective” if undis- processing before sale, as shown in Figure 3.20. Tight
covered but with different degrees of geological probability and shale gas, coal-bed methane (CBM), and natural gas
of existence. Discovered resources are classified as “con- hydrates (NGH) are commonly referred to as unconven-
tingent” (noncommercial) or “reserves” if the economic tional gases, whereas heavy and extra-heavy oil, bitumen,
and technical evaluation declares the resources commer- and oil shale are the corresponding unconventional oils.
cial with current technologies. Contingent resources and
reserves present different degrees of probability. In the 3.3.2 Crude-Oil Reserves
latter, the common definition of “proven,” “probable,” and 3.3.2.1 Conventional Crude Oil
“possible” stands for discovered hydrocarbons for which According to EIA [13] total proven world oil reserves as of
there are 90 %, 50 %, and 10 % probability, respectively, January 1, 2009 were 1342 billion bbl, with a geographi-
that they can be extracted profitably with the field devel- cal distribution in various parts of the world as shown in
opment assumptions. The common notation of reserves Figure 3.21. This is somewhat greater than the 1258 billion
as 1P, 2P, and 3P is related to the degree of probability bbl in 2008 that were given in Table 3.1, maintaining the
used in the definition. Proven reserves information will trend observed during the last decades. During the period
be used through the statistics in this chapter except when of 1980–2008, shown in Figure 3.22, global proven oil
indicated. reserves have presented a continuous yearly increase as a
These classifications allow for homogeneity in the result of successful prospection activities and production
definition and classification, but they do not affect the mea- technology developments [4,11]. Although in most regions
surement, which, in practice, will depend on each country’s proven reserves increased, in some areas the growth has
legislation. It must be noted that there are two key issues not been relevant (Asia-Pacific) or reserves have even
significantly affecting the estimation of reserves in each
category: technology and price. Over the time, continuous
developments have made possible the transformation of
prospective resources into contingent resources through
the improvement in exploration technologies, whereas
production technologies allow for converting resources
into reserves. At the same time, the oil price fluctuations
may move resources to reserves with price increases, or the
opposite when there is a price drop, like the situation cre-

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
ated during the recent world economic crisis.
The differences in the basis used of the definition and
the factors affecting the classification have created confu-
sion over how much oil will be available for commercial
production in the long term, and they probably represent Figure 3.20—Conventional vs. unconventional hydrocarbons
one of the reasons that over the previous decades oil according to Society of Petroleum Engineers [26].

Figure 3.19—Hydrocarbon resource classification [26,28].

AST-MNL58-11-0801-003.indd 42 3/12/13 12:47 PM

Chapter 3 n Worldwide Statistical Data 43

decreased (North America). Six countries (Saudi Arabia, because of the decline the country is facing in several
Iraq, Kuwait, United Arab Emirates, Iran, and Venezuela) giant fields despite increased exploration efforts. Inclu-
control most world crude oil, accounting for two thirds of sion of unconventional oil may significantly increase
proven reserves. Changes in oil reserves from 1980 to 2008 oil reserves in regions such as Canada.
in different geographical areas are shown in Figure 3.23, • South and Central America: These areas have largely
A and B, detailing the distribution and most relevant varia- increased their reserves from 1980, most of them
tions in countries covering most reserves. coming from Venezuela, which increased their proven
• Middle East: The region had the greatest increase of reserves 5 times in that period. In 2008 the region
proven reserves in the analyzed period and accounted accounted for approximately 10 % of world reserves,
for 60 % of world reserves in 2008. Although new oil with increasing impact of the new deepwater reservoirs
reserves continue to be discovered all over the world, in Brazil.
most forecasts indicate that dependence on Middle • Europe and Eurasia: The change in reserves from the
Eastern oil will increase in the coming years with former Soviet Union to the new political distribution
the decline of other basins. All of the countries have makes it difficult to compare data from the period
increased their reserves in the last decades, with Saudi before 1998. However, as a summary, most of the
Arabia accounting for more than one third of the reserves growth in the area is from the Russian Federa-
region reserves. tion and Kazakhstan, whereas most European fields,
• North America: North America is the second area in especially in the North Sea, are facing a significant
proven reserves, and the only area with a net reserves decline. In 2008, the area accounted for approximately
reduction in the last decades. The contribution to 11 % of world reserves, without significant change dur-
world reserves fell from approximately 15 % in 1980 to ing the last years.
approximately 6 % in 2008. Most of this reduction is • Africa: The development of North and West Africa in
related to Mexican challenges in reserves replacement the late 1990s and during this decade has produced
a continuous increase in proven reserves that allow
Africa to maintain its average 10 % contribution to
world reserves. Libya, Nigeria, and Angola accounted
for the main increase in reserves during this period.
• Asia-Pacific: The contribution of this area to the world
reserves is minor (~3 % in 2008) and has not changed
significantly in the last decades. The decline of Indone-
sian fields has been replaced by new reserves in differ-
ent countries without discoveries with a major impact
in the area reserves.
The data used to build previous charts and analysis
correspond to proven reserves [4]. There are significant dif-
ferences in estimates from existing resources that could be
moved to reserves through adequate oil price and technol-
ogy availability. As a reference, Lakatos [17] estimated with
data from USGS world proven reserves to be approximately
Figure 3.21—World proven oil reserves geographical distribu- 170 Gt, with another 155 Gt in predicted resources, for a
tion (January 1, 2009) [13]. total crude-oil reserves estimation of 325 Gt.
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Figure 3.22—World conventional oil reserves (a) evolution and (b) changes 1980–2008 [4].
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44 Petroleum Refining and Natural Gas Processing

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Figure 3.23A—Regional conventional oil reserves (a) evolution and (b) changes 1980–2008 [4].
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Chapter 3 n Worldwide Statistical Data 45

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Figure 3.23B—Regional conventional oil reserves (a) evolution and (b) changes 1980–2008 [4].
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46 Petroleum Refining and Natural Gas Processing

3.3.2.2 Unconventional Crude Oil

Fast depletion of conventional oil and the increase in oil
price provides an opportunity for other available sources
of energy such as heavy oils, bitumen, and tar sands, usu-
ally known as unconventional oils. As shown in Figure 3.1,
heavy oil is very viscous, with viscosity ranges from 10 to
10,000 cP. This makes it difficult to flow, avoiding conven-
tional oil production in some places through conventional
methods, and with recovery factors for heavy-oil reserves
less than 10 %. Heavy oils have an API gravity less than
20 and are deficient in hydrogen, having higher aromatic
hydrocarbon, sulfur, and heavy metal content, which
increases the processing cost as compared with conven-
tional and lighter oils.
Distribution of heavy oil throughout the world is shown
in Figure 3.24. IEA estimates that there are approximately
6 trillion bbl in place worldwide, from which 2.5 billion bbl Figure 3.25—Conventional and unconventional oil reserves:
are in Canada, 1.5 billion bbl in Venezuela, 1.0 billion bbl in Numbers are in billions of barrels [31].
the Russian Federation, and 0.1–0.2 billion bbl in the United
States [29,30]. Other sources propose alternative data: If
extra-heavy oil and bitumen are also considered in this
estimate, then the total oil reserves are more than 10 tril- bitumen (~400 billion m3), whereas Venezuela’ reserves are
lions bbl. Total amount of proven conventional oil reserves mainly heavy oil (~230 billion m3). Iraq and Kuwait each
is more than 1.3 trillion bbl. Distribution of conventional have heavy-oil reserves of approximately 30 billion m3 each.
versus unconventional oil around the world is shown in The United States and Nigeria also have bitumen reserves
Figure 3.25 [31]. More detailed distribution of heavy oil of approximately 20 billion m3 each according to Schlum-
and bitumen in different regions and the world is shown berger [33]. In addition to these heavy oils, more discover-
in Figure 3.26. Although in the Middle East most proven ies are being made for conventional oils from countries
oil reserves are conventional oil, which can be produced that have not been known for their oil reserves. The best
with conventional methods, in Canada most oil reserves are example of this group of countries is Angola in Africa, with
unconventional and bitumen type, which may be produced reserves now standing at 20 billion bbl of oil. Most recently,
with techniques yet to be developed with higher oil price. some new giant oil fields have been discovered in Saudi
Canada’s oil reserves are located in the province of Arabia, Iraq, and Iran. Proven Middle Eastern oil reserves
Alberta, and the oil production in Alberta is currently in 1980 were approximately 360 billion bbl and in 2007
approximately 1 million bbl/day, but this production will reached approximately 730 billion bbl, an increase of more

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increase in the future. In addition, Alberta has large oil than 100 % in 27 years.
sand reserves that can hold billions of barrels of oil. Figure 3.27 represents unconventional oil resources
Alberta’s internationally recognized oil reserves now stand and production cost compared with other energy sources
at 175 billions bbl of oil. This is the world’s second-largest [34]. Despite technology efforts, unconventional oil pro-
crude reserve after Saudi Arabia’s oil reserves. However, duction needs significantly higher crude-oil prices to make
the cost of oil production from oil sand is high because the this energy source more economic [35]. Carbon emissions
process of separating oil from the sand is energy- and labor- and water requirements present additional challenges com-
intensive and as such it has been cost-effective when global pared with conventional oil production, which can make
oil prices have been high. Analyses estimate world oil prices required oil prices even higher for heavy-oil exploitation to
need to be more than $80/bbl for the Canadian oil sands to become feasible.
be economically viable [32]. Canada’s reserves are mainly
3.3.3 Natural Gas Reserves
3.3.3.1 Conventional Gas
Distribution of natural gas reserves in different regions and
the world according to EIA [13] is shown in Figure 3.28.
From these data, the estimated world total conventional
gas reserves is 6254 trillion ft3, compared with the data
published by BP [4] of 6534 trillion ft3 referenced in Table
3.1. Natural gas reserves are widely distributed around the
world in association with petroleum or as dry gas. Dur-
ing the period of 1980–2008, shown in Figure 3.29, global
proven natural gas reserves have doubled, with trends
similar to those observed in crude-oil reserve evolution.
By far most proven reserves of natural gas are located in
three countries—Iran, Qatar, and the Russian Federation—
accounting for more than half of the world’s reserves.
Changes in gas reserves from 1980 to 2008 in different geo-
Figure 3.24—Distribution of heavy oil in the world [29]. graphical areas are shown in Figure 3.30, A and B, which
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Chapter 3 n Worldwide Statistical Data 47

(a) 1600 (b) 3000

1400
2500

Bitumen reserves in billions barrels

Heavy oil reserves in billions barrels

1200

2000
1000

800 1500

600
1000
400
500
200

0 0

2500

2000

1500

1000

500
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a

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ai

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ad

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er
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i
ex
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ua
an

ig
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Figure 3.26—Global distribution of heavy oil and bitumen: (a) heavy oil, (b) bitumen, (c) heavy oil and bitumen total. CIS (Common-
wealth of Independent States) refers to all countries of Former Soviet Union (USSR) except Baltic states and its headquarter is in Minsk.

Figure 3.27—Resources/production curve of heavy oils compared with other energy sources [34].
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48 Petroleum Refining and Natural Gas Processing

• Europe and Eurasia: As was mentioned with crude-oil

data, the period before 1998 is difficult to compare
in the former Soviet Union. Most of the reserves are
located in the Russian Federation, which accounts
for approximately 25 % of world natural gas proven
reserves.
• Africa: North Africa (Algeria and Libya) possesses most
gas reserves in the continent of Africa, although signifi-
cant increases took place in the last decades in West
Africa (Nigeria) and Egypt, maintaining the contribu-
tion to world gas reserves at approximately 7 %.
• Asia-Pacific: The contribution of this area to the world
reserves has increased in the period, with additional
reserves in most countries. Indonesia, Australia, China,
and Malaysia account for most of the reserves, which
correspond to approximately 8 % of world reserves.
Figure 3.28—World natural gas reserves by geographic region The challenge to move resources to reserves in natural
(January 1, 2009) according to EIA [13]. gas is likely to come from unconventionals, especially shale
gas. However, to transport gas from production to demand
centers is a major issue because many of the largest
details the distribution and most relevant variations in the
reserves are in remote areas. Russian gas is exported mainly
main producing countries.
to northern European countries, whereas southern Europe
• Middle East: The Middle East also holds the largest
is supplied with Algerian gas. As in the case of oil reserves,
world natural gas reserves, having increased proven
the Middle East holds the largest gas reserves in the world,
reserves approximately 4 times and accounting in 2008
but in this case they are more difficult to move to market.
for approximately 40 % of world reserves. All Middle
Eastern countries have increased their reserves in the 3.3.3.2 Unconventional Gas
last decades, especially Qatar and Iran. Although natural gas increased its contribution to the
• North America: North America is one of the areas with energy mix during the last decades, the same did not

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
less proven natural gas reserves (<5 %) and is the only happen with unconventional gas (shale gas, tight gas,
area with a net reserves reduction in the period. Can- and CBM). Until the last years, the attention in most of
ada and Mexico are responsible for this decline, with a the world was still focused on conventional natural gas
minor increase in U.S. proven reserves. However, the reserves, with very few cases of unconventional gas devel-
contribution of the United States to unconventional gas opment. According to Figure 3.27, to make unconventional
reserves, especially shale gas, is significant. gas development economically feasible requires equivalent
• South and Central America: South and Central America oil prices to be even higher than unconventional crude oil.
have largely increased their reserves from 1980, with However, the recent boost in production levels from shale
most coming from Venezuela, which increased its gas in the United States and the huge potential resources
proven reserves approximately 4 times in that period, as available in different areas are starting to make unconven-
well as the new Bolivian reserves. The global contribu- tional gas field development attractive.
tion to gas reserves is minor in the rest of the countries Although there is not an agreement among different
of this area, with a decline in Argentinean reserves. sources regarding the estimated gas volumes in place, most

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Figure 3.29—World conventional gas reserves (a) evolution and (b) changes 1980–2008 [4].
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Chapter 3 n Worldwide Statistical Data 49

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Figure 3.30A—Regional conventional gas reserves (a) evolution and (b) changes 1980–2008 [4].
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50 Petroleum Refining and Natural Gas Processing

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Figure 3.30B—Regional conventional gas reserves (a) evolution and (b) changes 1980–2008 [4].
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Chapter 3 n Worldwide Statistical Data 51

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1RUWK /DWLQ (XURSH )68 0LGGOH(DVW :HVW $VLD $VLD
$PHULFD $PHULFD 1RUWK$IULFD $IULFD &HQWUDO 3DFL¿F

Figure 3.31—Estimated unconventional gas reserves by area [36].

of them agree on the large amount of resources. As a refer- 3.4 Petroleum, Natural Gas, Coal,
ence [36], a significant number of basins in the world could and Biofuel Production
contain unconventional gas on the order of magnitude of In previous parts of this chapter, demand and reserves were
16,000 trillion ft3 of shale gas, 7400 trillion ft3 of tight sand discussed; this section deals with production, the third part
gas, and 9000 trillion ft3 of CBM. The estimated distribution of the energy equation, through data on oil and gas produc-
of these resources by type and geographic area is shown tion and reserves and estimated reserves life in different
in Figure 3.31. The main contributions would come from regions and the world. Most of the presented data, as in
North America (>8000 trillion ft3 between shale gas and previous parts, are taken from the recent data published by
CBM), FSU (5500 trillion ft3, mainly CBM) and Asia Central EIA [13], IEA [18], and the BP Statistical Review of World
and Pacific (~5000 trillion ft3 each, mainly shale gas). Energy [4]. The limited flexibility and sensitivity to external
The new approach to unconventional gas started in the factors of the oil market was stated at the beginning of
United States about a decade ago with small developments this chapter [15]. Because consumption of oil and gas in a
in CBM and tight gas. The scenario changed completely with region depends on the availability of alternative sources of
the development of Barnett in the first half of this decade energy, production and consumption of coal and biofuels
and other main North American gas shales (Haynesville and are also presented in this part.
Marcellus) in recent years [37]. Over the last decade, U.S.
shale gas production has almost increased 1 order of mag- 3.4.1 Geographic Distribution and
nitude, with 80 billion m3 of production in 2008, and it is Future Trends
becoming a game changer in North America by significantly 3.4.1.1 Crude Oil
reducing requirements for natural gas imports in liquefied Production of crude oil and its projection to 2015 in various
natural gas (LNG) form relative to past scenarios. regions are presented in Figure 3.32a and for the world in
Other potential sources of natural gas, such as natural Figure 3.32b [11]. Table 3.5 details the world oil production/
gas hydrates (NGHs), are more speculative. Although NGHs consumption balance, showing that excess production rela-
have attracted significant attention because estimates indi- tive to internal consumption in the Middle East and Africa
cate potential resources several orders of magnitude larger covers the deficit in OECD and Asia-Pacific countries.
than present natural gas reserves, significant technical chal- However, relative production rates in some major produc-
lenges exists to make these resources feasible for exploitation. ers, mainly OPEC countries, are significantly lower than in

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0LOOLRQV%DUUHOV2LO3HU'D\

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$PHULFD $PHULFD (XURDVLD

Figure 3.32—Oil production in recent decades and forecast to 2015 (a) by region and (b) in world [11].
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52 Petroleum Refining and Natural Gas Processing

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Figure 3.33—Absolute and relative oil production in top 20 producing countries ( OPEC countries non-OPEC
countries) [4].

other areas. According to the BP statistical review [4], OPEC ing moving resources to reserves [41,42]. Recent studies
countries accounted for 76 % of world oil proven reserves in [43] estimate that peak oil was probably July 2008 unless
2008, whereas in the same period they hardly reached 45 % oil prices rise sustainably over $75/bbl. Additional oil price
of world oil production. This difference is shown in Figure increases would help move more resources to reserves and
3.33, comparing absolute and relative production rates in support enhanced oil recovery (EOR) processes that would
the top 20 crude-oil-producing countries. The clear differ- significantly delay this peak oil estimate.
ence between OPEC countries and the rest is probably the
result of two main factors: internal compliance with OPEC 3.4.1.2 Natural Gas
quotas to stabilize oil prices and less production facilities Major gas producers are in the regions of North America
in some Middle Eastern countries with major oil reserves. and Eurasia. Russia, Iran, and Qatar combined have 57 %
This gap will unlikely be sustainable in time because the of world natural gas reserves [14]. Production of natural gas
capability from non-OPEC countries to supply additional and projections to 2030 in various regions and the world are
oil to the market will be reduced with the depletion of their presented in Figure 3.35 [4,17]. Table 3.6 details the world
reserves at a much higher rate than OPEC countries. natural gas production/consumption balance, showing that,
Several countries with significant production growth similar as to what occurs with crude oil, excess production
during the last decade depend on high-cost deepwater relative to internal consumption in the Middle East and
projects to maintain their increasing production. However, especially Africa covers the deficit in OECD and Asia-Pacific
many exploration and development projects that were countries. Figure 3.36 compares absolute and relative pro-
delayed during the economic crisis, mostly deepwater and duction rates in the top 20 natural-gas-producing countries,
heavy-oil projects, are still not economical and wait for showing trends already observed with crude oil: higher
sustainable higher oil prices according to Figure 3.27. Some production rates for OECD countries and lower rates for the
surveys are anticipating challenges to supply the required Middle East. Peak theories also focus on natural gas produc-
oil to the market on the basis of the current oil prices sce- tion, although estimated peak gas is expected to occur with
nario, with a probable supply crunch appearing during this a delay with respect to peak oil according to Figure 3.34.
decade irrespective of demand level [38].
This risk would be in addition to the warnings received 3.4.1.3 Coal
about the world being at a crude-oil production plateau Consumption of oil and natural gas is related to the con-
and facing a sharp decline. The debate about this “peak oil” sumption of coal in the world. Coal is the second source
is not new because these widely discussed theories have of energy consumption in the world after oil. The United
existed for decades, mainly based on the original Hubbert States and China are the major coal producers and con-
model forecasts [39]. Most of the studies report peak oil sumers in the world. The major coal-consumer countries
having already occurred during this decade [40], as shown in the world and their consumption in 2004 are shown in
in Figure 3.34. However, these predictions, based on in- [44]. China consumes more than twice that
depth modeling of every country’s oil production history, of the United States because more than 83 % of China’s
are very sensitive to considerations about new discoveries, electricity is produced from coal-burning power plants.
new technologies, oil prices, and generally any factor allow- According to Germany’s Energy Watch Group [45], coal
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Chapter 3 n Worldwide Statistical Data 53

Figure 3.34 —Occurrence of peak oil, gas, and coal [40]. Production rates are in gigatons of oil equivalent (Gtoe).
For energy equivalency see Table 3.3.

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1RUWK 6 &HQW (XURSH 0LGGOH(DVW $IULFD $VLD3DFL¿F

$PHULFD $PHULFD (XUDVLD

Figure 3.35 —Gas production in recent decades and forecast to 2030 (a) by region and (b) in the world [4,17].

Table 3.5—Crude-Oil Production/

Consumption Balance in 2008 [4] production in most producing countries peaks around
2025, as shown in Figure 3.38. A graph of peak oil is
Oil Balance
Production Consumption (Production –
shown in Figure 3.34, which shows similar behavior for all
Region (103 bopd) (103 bopd) Consumption) three major fossil-type fuels: oil, gas, and coal. Peak oil is
followed by peak gas and then peak coal, although these
North America 13.131 23.753 –10.622 predictions are different from one source to another. Oil
South and 6.685 5.901 784 reserves are decreasing in many countries, especially in
Central America the Asia-Pacific region where consumption of the sources
of energy such as coal and gas is increasing. As production
Europe and 17.591 20.158 –2.567
of energy from conventional and nonrenewable sources
Eurasia
decreases, attempts are being made to produce energy
Middle East 26.200 6.423 19.777 from unconventional oil and renewable energy sources
Africa 10.285 2.881 7.404
such as biofuel and solar energy [13].
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Asia-Pacific 7.928 25.339 –17.411 3.4.1.4 Biofuels

World (total) 81.820 84.455 –2.635 Biomass is basically organic material made from plants and
animals that can be converted to fuels such as ethanol or
bopd = barrels of oil per day biodiesel, known as biofuels. Biomass fuels provide 3 % of
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54 Petroleum Refining and Natural Gas Processing

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Figure 3.36—Absolute and relative gas production in top 20 producing countries [4].

Figure 3.37—Major coal-consuming countries in 2007 [44].

sulfur dioxide (SO2), a cause of acid rain. However, burning

of biomass does produce carbon dioxide (CO2), a GHG pol-
lutant, but plants use CO2 in their photosynthesis process.
Different plants produce different amounts of biofuels,
as shown below in terms of liters of produced fuel per hect-
are of required planted land [13,46].
Production of ethanol from different plants:

Plant Wheat Corn Sugar Beet Sugar Cane

Liters/hectare 2500 3000 5000 6000

Production of biodiesel from different plants:

Caster Sunflower Grape

Plant Soybeans Beans Seed Seed Jatropha Palm
Figure 3.38—World coal production from 1950 and prediction
to 2100 [45]. Liters/ 600 800 1000 1200 1900 4500
hectare

the energy used in the United States and their production is Biofuel production is expected to grow at 8–12 % per
increasing. Biodiesel is one of the fastest growing alternative year as in 2006 the production rate was 0.86 MBPD (1000 bbl/
fuels and can be used in diesel engines. Biomass does not day), while in 2017 it is expected to be at 2.2–3.0 MBPD. The
contain sulfur, so when it is burned it does not produce potential market size is $38 billion/year, or 2.2 million bbl/day
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Chapter 3 n Worldwide Statistical Data 55

Bioethanol Biodiesel
20 2.5

16 2.0
95% growth 295% growth
12 2.5
Mtoe

Mtoe
8 1.0

4 0.5

0 0
2000 2001 2002 2003 2004 2005 2000 2001 2002 2003 2004 2005
Brazil United States European Union China India Other Germany France Italy Rest of Europe United States Other

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Figure 3.39—Production of bioethanol and biodiesel from 2000 to 2005 in terms of Mtoe [48].

3.4.2 Reserves/Production Ratios for

Geographical Distribution
The reserves-to-production ratio (R/P) is one of the most
widely used parameters when forecasting reserves life. Its
simplicity and possibility to be easily determined from lim-
ited data available in open literature make it one of the most
popular parameters for this type of study. Although this ratio
will be used in this section to compare data from different
parts of the world, it should be pointed out that these com-
parisons must be taken with caution and analyzed under
proper interpretation. The lifetime of a reservoir determined
from this ratio is determined in a certain moment from the
ratio of the amount of hydrocarbon remaining in the reser-
Figure 3.40—Production of bioethanol and biodiesel from voir to the yearly production rate. Because both parameters
1975 to 2005 [47]. (the amount of hydrocarbon in the reservoir and the produc-
tion rate) change during the field development cycle, these
at $50/bbl. Bioethanol is the most common biofuel, account- values are expected also to change. The type of reservoir may
ing for 90 % of total biofuel. Bioethanol can be produced significantly affect the R/P: highly permeable reservoirs may
from corn, sugar cane or sugar beets, and potatoes. The produce an annual rate of even 15 % of the reserves, whereas
world’s largest producers of bioethanol are Brazil (from sugar low permeability reservoirs cannot provide more than 1–2 %
cane) and the United States (from corn). Ethanol is used in [49]. The ultimate recovery factor may also vary significantly
low 5–10 % blends with gasoline indicated as E5 and E10, from one reservoir to another depending on parameters
respectively. Figure 3.39 shows the increase in production of such as aquifer support or the presence of water-flooding or
bioethanol and biodiesel from 2000 to 2005, which indicates EOR processes. On the other hand, production rate depends
an increase of 95 and 295 %, respectively [47,48]. A similar on the number of wells defined in the field development
figure from the U.N. Environment Programme (UNEP) that plan, which may be very different from one field to another
shows the volumetric annual rate production of bioethanol or even during the development of the same field.
and biodiesel is presented in Figure 3.40. Even with these limitations, and with the objective
The issue of use of biofuel as an alternative energy is of comparison with other published information, the R/P
controversial because there are some opponents of such parameter will be used in this chapter. Data presented in
energy. For example, in a major cover story article in Time this section show the lifetime of oil and gas reservoirs in
magazine, Michael Grunwald argues that politicians who various regions on the basis of the specified date for the
try to substitute oil with biofuel in fact are pushing food production rate. On the basis of production rate in 2008,
prices up and making global warming worse [46]. He argues the calculated lifetime of conventional oil in the top 20
that all processes in the manufacture of bioethanol are net producing countries are shown in Figure 3.41a. As shown
carbon emitters except those produced from sugar cane. He in this figure, the average lifetime of oil reservoirs in OPEC
estimated that the size of the biofuel industry in 2010 would countries, especially the Middle East and Venezuela, are
be approximately $100 billion. The state of Iowa produces among the highest, as mentioned in the section on produc-
one third of U.S. ethanol, and in 2007 it produced 7.5 billion tion. It is important to mention that these data are calcu-
L of bioethanol. Brazil is hailed as the global biofuel suc- lated on the basis of conventional oil. If unconventional
cess and it produced 19 billion L of sugar cane ethanol and oil reserves are considered, lifetimes in countries such
supplied 45 % of its transportation fuel in 2007. The United as Canada, Venezuela, or the Russian Federation would
States leads the world in soybean and corn production, and greatly exceed what is shown in the figure.
if 100 % of these were converted into fuel, it would provide Lifetime of conventional gas reserves in the top 20 pro-
only 20 % of road vehicle fuels as argued by Grunwald. ducing countries on the basis of 2008 production rates are
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56 Petroleum Refining and Natural Gas Processing

D
6DXGL$UDELD
Table 3.6—Natural Gas Production/
5XVVLDQ)HGHUDWLRQ
Consumption Balance in 2008 [4]
86 Gas Balance
,UDQ Production Consumption (Production –
&KLQD Region (bcm pd) (bcm pd) Consumption)
&DQDGD North America 812 824 –12
0H[LFR
South and 159 143 16
8QLWHG$UDE(PLUDWHV
Central America
.XZDLW
9HQH]XHOD Europe and 1.087 1.144 –57
1RUZD\ Eurasia
,UDT Middle East 381 327 54
1LJHULD
$OJHULD Africa 215 95 120
%UD]LO Asia-Pacific 411 485 –74
$QJROD
World (total) 3.065 3.018 47
/LE\D
.D]DNKVWDQ bcm pd = billion cubic meters per day
8QLWHG.LQJGRP
4DWDU
Table 3.7—Crude Oil and Natural Gas

Proven Reserves Average Lifetime Based on
3URGXFWLRQOLIHWLPH\HDUV 2008 Data [4]
E Crude-Oil Reserves Natural Gas Reserves
5XVVLDQ)HGHUDWLRQ Region Lifetime (years) Lifetime (years)
86
North America 14.8 10.9
&DQDGD
,UDQ South and 50.5 46.0
1RUZD\ Central America
$OJHULD Europe and 22.2 57.8
6DXGL$UDELD Eurasia
4DWDU
Middle East 78.9 199.2
&KLQD
,QGRQHVLD Africa 33.5 68.2
8QLWHG.LQJGRP
Asia-Pacific 14.5 37.4
1HWKHUODQGV
7XUNPHQLVWDQ World (total) 42.1 60.4
0DOD\VLD
8]EHNLVWDQ constant in the range of 40–45 years since the mid-1980s,
(J\SW whereas in the case of natural gas the variations have been
0H[LFR similar in the range of 60–70 years, with the exception of
8QLWHG$UDE(PLUDWHV a decline in the first part of this decade. The explanation
$UJHQWLQD of this phenomenon is related to the definition of the R/P
7ULQLGDG 7REDJR parameter in itself relative to proven reserves. Any move-
ment of resources to reserves (new discoveries, oil price,

and technology) affects extending the lifetime, whereas on
3URGXFWLRQOLIHWLPH\HDUV the production side energy demand is growing mainly in
23(&FRXQWULHV 1RQ±23(&FRXQWULHV developing countries.
Figure 3.43 shows a projection of oil consumption and
Figure 3.41—Estimated average production lifetime for
(a) conventional oil and (b) natural gas for top 20 producing production until 2015 (on the basis of data from BP) [50].
countries (2008) [4]. The gap in consumption will probably cause an increase
of oil prices in the future, and it is one of the reasons that
more fuel-efficient cars have been manufactured in recent
shown in Figure 3.41b. Qatar and Iran have the longest natu- years to keep consumption under control. One important
ral gas lifetime. Table 3.7 compares the average lifetime for factor that affects world energy consumption is the rate
crude oil and gas proven reserves, confirming that for gas the of population growth in the world. A higher population
expected lifetime is longer than for crude oil (60 vs. 42 years). certainly demands a higher energy consumption rate. The
However, these estimations must be handled with cau- change of population in different regions and the world is
tion. Figure 3.42 shows the change in the average lifetime demonstrated in Figure 3.44 [51]. As shown in this figure,
for crude oil and gas reserves during the last decades. the world population may reach 10 billion by 2050, a
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

In the case of crude oil, the value has remained almost 40 % increase from the current figure of approximately
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Chapter 3 n Worldwide Statistical Data 57

:RUOG&UXGH2LO5HVHUYHV/LIHWLPH\HDUV

:RUOG*DV5HVHUYHV/LIHWLPH\HDUV

&UXGH2LO
*DV

Figure 3.42—Crude-oil and gas proven reserves average lifetime (1980–2008) [4].

EEOGD\

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

2LOSURGXFWLRQ
2LOFRQVXPSWLRQ

<HDU
Figure 3.43—Gap between oil consumption and production
in the world will increase oil prices on the basis of data from
EIA [13].

Figure 3.44—Population growth rate until 2050 [51]. Source:

7 billion. Africa shows the largest population growth Reprinted with permission from Oxford Analytica, Ltd. ©
whereas Europe shows a slight decrease in population over 2010.
the next 4 decades.
According to estimations from the USGS for the energy
demand for the period 2000–2100, the global cumulative the various components of crude oil and process these frac-
demand on crude oil and natural gas will reach 206 Gt. tions with diverse operation to minimize the heavier frac-
The world proven reserves currently is at approximately tion, lower-value products (e.g., residual fuel oil) in favor of
170 Gt, and there are approximately 155 Gt of predicted lighter, higher-value products (e.g., gasoline) [52]. On the
resources, which puts the total oil and gas reserves at other hand, refining margins are defined as the difference
325 Gt. If only 50 % of these resources are recoverable with in value between the products produced by a refinery and
existing technology, then total production by 2100 would the value of the crude oil used to produce them. Refining
be approximately 162 Gt, which indicates there would be a margins will thus vary from refinery to refinery and depend
62 % deliverability gap for oil and gas [17]. This shortage on the price and characteristics of the crude [53]. Petro-
will need to be compensated for by other sources such as leum refining processes and operations can be separated
renewable energies. into three basic areas: fractionation (distillation), conver-
sion (changing the molecular size, structure, or both), and
3.5 Refining of Petroleum and treatment (removal of undesirable contaminants). There
Processing of Natural Gas are some other processes such as blending and mixing of
3.5.1 Worldwide Refinery Capacity different fractions of petroleum that are widely used in the
Petroleum refining is a continuously changing process that refinery [13,54–56]. Refiners face tough challenges when
varies with consumer demand. Included in the downstream they adapt or design refineries for heavy- or extra-heavy
processing refinery capacities are the production of finished crude-oil processing. The most common configuration
petroleum products and the distribution, marketing, and includes distillation, thermal cracking, catalytic cracking,
shipping of the products. Refining processes fractionate hydrocracking, and hydrotreating. The selection of one or
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58 Petroleum Refining and Natural Gas Processing

more refinery processes is based on the best possible combi- refineries. The largest petroleum processing companies are
nation for obtaining a clean and valuable fossil fuel (natural reported in Figure 3.46, along with their process capacity
gas, oil, and coal) energy source to suit the market demand. [4,13,54,57–59]. Major changes in the refiners’ position
The global refineries’ capacities are extending in a have occurred among Valero, Chevron, Total, and Mara-
big way, as evident in the record increase in recent years thon, whereas others generally move up and down the list
despite a decreasing trend in the observed number of by one or two positions. There are approximately 700 refin-
refineries because larger refineries are being built whereas eries all over the world (currently operating ~662 refiner-
others are being closed because of economic reasons ies). The regional distribution of worldwide total refineries
such as low refining margins, small local markets, high is shown in Figure 3.47. The utilization of installed refinery
operating costs (because of small size), and poor yields. capacities by region are particularly displayed with number
In the last decade more than 100 refineries have closed— and their percentage rank in the region.
typically smaller, less-efficient ones. It is obvious that A chronological development in refinery capacities is
strong decreasing trends in western and central Europe reported in Table 3.9. The first step of the refinery is to
and North America caused a global decrease in refinery separate the crude-oil component using thermal fractional
numbers. The global refinery utilization rate will continue distillation, in which the oil is heated and then broken
to decline to an average 78 % of capacity in 2015, compared down according to different boiling points. Figure 3.48
with 84 % in 2008 and approximately 81 % in 2009. For shows the total capacity of atmospheric and vacuum distil-
2010, a survey indicated total capacity to be more than lation as a function of time (1970–2010) and region. The
88 million bbl/day in 662 refineries, an increase of 1 mil- distillation process is the most important and is available
lion bbl/day from the 2009 figure of 87 million bbl/day for in most refineries. A regional distribution of atmospheric
661 refineries. In Figure 3.45 an increase of more than 1.6 and vacuum distillation in different refinery capacities is
million bbl/day over 2008 is reported. In 2009, capacity shown in Figure 3.49. The global refining crude-oil distilla-
growth surpassed the total growth for the previous 3 years: tion is expected to increase from 9 million bbl/day in 2009
2008 (300,000 bbl/day), 2007 (130,000 bbl/day), and 2006 to 99 million bbl/day in 2015. The largest increase will come
(52,000 bbl/day). On the other hand, worldwide demand from Asia and the Middle East. Most refineries worldwide
(2009) averaged 86.3 million bbl/day, rebounding from the never work at their full capacity; an example of a U.S. dis-
2008 average of 84.9 million bbl/day and nearly reaching tillation unit capacity is given in Figure 3.50. Utilization of
the 2007 average of 86.5 million bbl/day. The output of refinery capacities in practice is necessarily functionally
oil has increased since 2009 to an average 86 million bbl/ related to installed capacities and is equally proportionate
day compared with 84.9 million bbl/day last year and 86.4 for the same periods, but not with the same intensity in all
million bbl/day 2 years ago. A worldwide list of the top 20 regions, nor with equal enunciation. In general, the differ-
refineries is reported in Table 3.8, which includes refinery, ences in utilization of installed refinery capacities by region
location, and crude-oil daily processing capacity. The new are high in the Middle East, North and Latin America,
Reliance refinery has now become the petroleum hub of western and central Europe, Asia, and the Pacific. This is
the world in Asia by increasing to 1.24 million bbl/day for followed by Africa, whereas east Europe and central Asia
crude processing capacity. Reliance is the single largest are at the end of the list. Not only that, eastern European
refining complex (Jamnagar) in the world, which is equiva- (<17), African (<20), and Middle Eastern (<22) refineries
lent to 1.6 % of the global capacity or one third of India’s have the lowest average complexity ratios in comparison
capacity, which globally places it among the top 10 private to refineries in western and central Europe (<36), Latin

&DSDFLW\ 5HILQHULHV

&DSDFLW\PLOOLRQEEOGD\

5HILQHULHV

<HDU

Figure 3.45—Worldwide trend in operable refineries and their capacities [54].

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Copyright ASTM International

AST-MNL58-11-0801-003.indd 58 3/12/13 12:47 PM

Chapter 3 n Worldwide Statistical Data 59

Table 3.8 —World’s Largest Refineries, Their Locations, and Their Processing Capacity [54]
Rank Location Company Crude Capacity (b/cd)
1 Jamnagar, India Reliance Industrial, Ltd. 1,240,000
2 Cordon/Judibana, Falcon, Venezuela Paraguana Refining Center 940,000
3 Ulsan, South Korea SK Corporation 817,000
4 Yeosu, South Korea GS Caltex Corporation 730,000
5 Jurong/Pulau Ayer Chawan, Singapore ExxonMobil Refining and Supply Co. 605,000
6 Baytown, TX ExxonMobil Refining and Supply Co. 576,000
7 Onsan, South Korea S-Oil Corporation 565,000
8 Ras Tanura, Saudi Arabia Saudi Arabian Oil Co. (Saudi Aramco) 550,000
9 Mailiao, Taiwan Formosa Petrochemical Co. 540,000
10 Baton Rouge, LA ExxonMobil Refining and Supply Co. 504,000
11 St. Croix, Virgin Islands Hovensa LLC 500,000
12 Mina Al-Ahmadi, Kuwait Kuwait National Petroleum Co. 466,000
13 Pulau Bukom, Singapore Shell Eastern Petroleum Co. 462,000
14 Texas City, TX BP PCL 451,000
15 Lake Charles, LA Citgo Petroleum Corporation 440,000
16 Garyville, LA Marathon Petroleum Co. LLC 436,000
17 Pernis, The Netherlands Shell Netherlands Raffinadenj BV 404,000
18 Zhenhai, China Sinopec 403,000
19 Rabigh, Saudi Arabia Saudi Arabian Oil Co. (Saudi Aramco) 400,000
20 Yanbu, Saudi Arabia Saudi Aramco-Mobil 400,000
b/cd = barrels per calendar day

([[RQ0RELO&RUS
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6XQFR,QF
6.&RUS
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3URFHVVLQJ&DSDFLW\EEOG
Figure 3.46—World largest refineries rank (January 1, 2009) with their processing capacity [54].

America (<44), Asia-Pacific (<45), and North American is an effort to describe the investment cost of a refinery in
(<75), respectively. The complexity ratio (reported in the terms of the process operation being conducted. However,
parentheses) as a percentage of the refinery conversion this applies only to the process unit cost of the refinery, not
capacities of the total refinery (distillation) capacity is to the total refinery cost. The processing capacity of spe-
reported by world regions for 2008. The refinery complexity cialized processes such as thermal, catalytic cracking, and
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60 Petroleum Refining and Natural Gas Processing

:HVWHUQ(XURSH $IULFD their demand with respect to raw petroleum (crude oil),
$VLD
capacity to process, and efficient method to obtain clean
6RXWK$PHULFD fuel. Therefore, these countries require a huge amount of

export-import to accomplish their demand. Hence, the gap
between product demand and domestic refining capacity
indicates the need for imports, whereas the lack of refin-
eries or low capacity force them to refine their crude to
import and buy back for their necessary use. The product
import situation suggests more taxes, transportation, and
other duties. The refined product regional distribution and
total import-export per day is shown in Figure 3.53, indi-
cating their demand for the particular year 2006. It is also
reported in the previous section that the Middle East is the
largest oil-producing region, whereas most refining takes
place in the United States, Europe, or Asia. The largest
(DVWHUQ(XURSH refining capacity is in North America (in fact, the United
1RUWK$PHULFD
0LGGOH(DVW States), accounting for approximately one quarter of the

crude-oil distillation capacity worldwide. The growth in
Figure 3.47—Regional breakdown of worldwide refineries demand for light products such as gasoline and diesel has
(numbers) and their percentage distribution [13]. been matched by the growth in emissions control and the
emissions’ effects on the environment, as shown in Figure
3.54, indicating that hydroprocessing is the most significant
reforming are compared in Figure 3.51. These processes area of the refining processing. The U.S., Japanese, and EU
have endured over 60 years and remain the workhouse of sulfur specifications drive toward lower sulfur content (<10
the refinery. Catalytic reforming has similar distinction ppm), which is a concept that has spread to the developing
in its very important place; however, in recent years alkyla- countries of South America, Africa, and the Middle East
tion and isomerization promise to become more signifi- and Asia-Pacific regions.
cant in the reformulated era because of advancement in
those techniques. In the 1970s or early 1980s, refiners put 3.5.1.2 Refining Challenges and Limitations
more effort on hydroprocessing, particularly the removal The crude-oil scenario is changing every year as it becomes
of sulfur. Catalytic hydrocracking also offers flexibility in heavier with higher contaminants such as higher sulfur,
the product yield and specification, but at a higher process nitrogen, and metal contents, which require more severe
price. The worldwide regional distribution and comparison refining conditions or catalysts to produce cleaner and
is shown in Figure 3.52 and is mainly dominated by North valuable finished products [59–65]. The worldwide pro-
American refineries. duction of light crude oil is rapidly dwindling, whereas
extra-heavy crude-oil production is increasing [66,67].
3.5.1.1 Global Refining Trend Thus, processing of such crudes poses different challenges
The stricter fuel standards and more efficient fuel and for today’s refiners. In addition, the understanding of
combustion engines are required to protect our climate. such feedstock is limited or difficult to characterize at its
Nowadays, we have many vehicles—the “two SUVs in molecular level. The heaviest fraction of heavy crude oil is
every driveway syndrome”—thus the high value (ultraclean represented by asphaltenes. Asphaltenes are the precursors
fuel) demand for gasoline and diesel is at priority for all of most heteroatoms (S, N, etc.) and metals (Ni and V). An
countries. On the other hand, most countries do not fulfill asphaltene molecule may be 4–5 nm in diameter, which

Table 3.9—A Chronological Development in Oil Refinery

Period Refinery Configuration

1960s and before Distillation; thermal processing; pretreatment; reforming

1970s Vacuum distillation; catalytic cracking; hydrocracking/hydrotreating; visbreaking; residue fuel oil (low S, N, etc.)

1980s Elimination of Pb in gasoline; lowering S in gasoline and diesel; fluid catalytic cracking; reduction in SOx/NOx

1990s Isomerization; MTBE, ETBE, TAME, etc.; alkylation

2000s Hydrocracking (multistage reactor); inhibition effect (H2S, NH3, N compounds, aromatics, etc.); capacity increase,
esterification, etc.; deep hydrodesulfurization (<50 ppm)

2010 and beyond ULDS (<5 ppm); separation of N compounds before ULDS; alternative methods for ultradeep desulfurization
(desulfurization by adsorption, removal of N compounds by adsorption); feed blending technology and its
composition; selective conversion of bottom-of-barrel; industrial application of nanotechnology
SOx, oxides of sulfur; NH3, ammonia; MTBE, methyl tert-butyl ether; ETBE, ethyl tert-butyl ether; TAME, tert-amyl methyl ether; ULDS, ultralow deep
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
hydrodesulfurization.

Copyright ASTM International

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Chapter 3 n Worldwide Statistical Data 61

1RUWK$PHULFD 6RXWK$PHULFD (XURSH

(XUDVLD 0LGGOH(DVW $IULFD

$VLD 2FHDQLD :RUOG

'LVWLOODWLRQ7KRXVDQGVEEOGD\
'LVWLOODWLRQ7KRXVDQGVEEOGD\

<HDUV

Figure 3.48—Geographical evolution of crude-oil distillation process within 4 decades [13].

&UXGHRLOGLVWLOODWLRQFDSDFLW\ 9DFXXPGLVWLOODWLRQFDSDFLW\
$IULFD :HVWHUQ(XURSH $IULFD
:HVWHUQ(XURSH

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6RXWK$PHULFD
$VLD
6RXWK$PHULFD

(DVWHUQ(XURSH
1RUWK$PHULFD
1RUWK$PHULFD
(DVWHUQ(XURSH 0LGGOH(DVW
0LGGOH(DVW

Figure 3.49—Regional breakdown of atmospheric and vacuum distillation capacities and worldwide refinery distribution (bbl/
day) and their percentage.

is difficult to process in a refinery by catalytic systems worldwide energy oil demand is projected to continue with
[68,69]. Metals in the asphaltene aggregates are believed a high level of refining capability [4]; however, one should
to be present as organometallic compounds associated be confident that refineries will meet the increasingly strin-
with asphaltene sheets, making the asphaltene molecule gent product specifications and have the ability to meet
more complex. Asphaltenes are usually problems during future demands.
exploration, processing, and transportation because of their
polar and unstable (precipitation and sediment formation) 3.5.2 Worldwide Products Distributions
nature within processed or unprocessed streams. Hence, a 3.5.2.1 Demand for Petroleum Products
high content of asphaltenes creates a refining problem that and Transportation Fuel
is not easy to solve. Therefore, it is mandatory for research- Demand for petroleum products is inevitably increasing,
ers to understand the chemistry of the complex fossil fuel particularly in developing countries such as India, China,
feedstocks that are required to design suitable catalysts and Brazil. Their demand is centered on gasoline and
and conditions for processing. The processing complexity distillates (transportation fuel) because these countries are
of the feedstock is further enhanced when coupled with growing in their middle-class population. Thus, conversion
the demand for ultraclean fuels (diesel and gasoline). The
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
technologies become a key driver in improving refinery
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62 Petroleum Refining and Natural Gas Processing

Since 2000, North America (United States, Canada,

and Mexico) enhanced its diesel desulfurization capacity

by 3.7 %, whereas naphtha desulfurization capacity was
7KRXVDQGV%DUUHOVSHU'D\

augmented by 0.7 %. The regional consumption of refined

group products is shown in Figure 3.56. The gasoline

XWLOL]DWLRQ
demand in the United States is gradually growing whereas
in Europe it has been declining since 2000. Gasoline
demand in Europe has declined at an average 2.1 %/year
since 2000, and diesel demand has increased by 2 %. The
2SHUDEOH&'8 decline in European demand for gasoline can be a benefit

2SHUDWLQJ&'8 for U.S. refiners because it makes more gasoline supplies
8WLOL]DWLRQRI5HILQHU\&DSDFLW\ available to the world market.

3.5.2.2 Ultralow Sulfur Diesel Supply and
<HDU Demand
Figure 3.50—U.S. operable crude distillation units (CDU) capac- Producing low-emissions transportation fuels is one of the
ity and its utilization (thousand bbl/day) [13]. highest priorities for the petroleum industry. Thus, sulfur
removal from petroleum feedstocks is a forefront issue
in the refinery industry because of recently enacted envi-
ronmental protection laws. Reducing the level of sulfur in
profitability. The demand for middle distillates is growing diesel fuel will increase the durability and performance of
steadily, as shown in Figure 3.55a. According to a recent aftertreatment technologies used in automobiles to satisfy
estimate by IEA, distillates (jet fuel, kerosene, diesel, and the stringent clean air standards established globally. Sulfur
other gas oils) will continue to be the main growth driver in fuels is a pollutant, and reduction of sulfur beyond cur-
of world oil demand for the next few years [58,70,71]. rent requirements is beneficial from an air quality and pol-
Moreover, the latest forecast by IEA indicated that global lution control equipment standpoint. U.S. Environmental
oil demand will increase approximately 0.6 %/year during Protection Agency (EPA) rules required that 80 % of high-
2009–2015. According to the IEA projection, approximately way diesel supplies contained no more than 15 ppm sulfur
48 % of the global product demand growth over the next 5 for the period 2006–2010. After 2011, all highway diesel fuel
years will be concentrated in middle distillate fuels, which will be required to contain less than 15 ppm sulfur, at least
are dominated by diesel. This trend is likely to continue in the United States and EU. The need to find a solution for
for many more years. It appears that petroleum refining this considerable problem has led to a worldwide search for
capacity, demand, and consumption are mainly oriented appropriate hydrodesulfurization catalysts.
around the middle distillate. Within the middle distillate Only a few refineries currently produce diesel with sulfur
demand for passenger cars, sport utility vehicles, light in the 15-ppm range. However, the worldwide existence of
trucks, buses, and heavy-goods vehicles was 13.5 million the requisite technology does not ensure that all refineries
bbl/day in 2008, which will increase approximately 24 % will have that technology in place in time to meet the new
within next 12 years (i.e., 2020) as shown in Figure 55, b ultralow sulfur diesel (ULSD) standards. Widespread pro-
and c. duction of ULSD in the future will require many refineries

7KHUPDO &DW&UDFNLQJ 5HIRUPLQJ

3URFHVVLQJ&DSDFLW\7KRXVDQGVEEOGD\

<HDU

Figure 3.51—Chronological processing capacity of different processes [13].

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,

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AST-MNL58-11-0801-003.indd 62 3/12/13 12:47 PM

Chapter 3 n Worldwide Statistical Data 63

&DWDO\WLF&UDFNLQJ 6RXWK$PHULFD &DWDO\WLF5HIRUPLQJ

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Figure 3.52—Regional glance at worldwide refining operations for different processes [13].

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,PSRUWVRI5HILQHG3HWUROHXP3URGXFWV ([SRUWVRI5HILQHG3HWUROHXP3URGXFWV

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Figure 3.53—Geographical regions and total import-export of petroleum products [13].

to invest in major revamps or construction of new units. quality specifications for diesel fuel, requiring a minimum 50
Very-low-sulfur diesel products have been available com- cetane, 10 ppm sulfur, and 5 % aromatic contents. To meet
mercially in some European countries, Japan, and the these specifications, the refinery at Scanraff, Lysekil, near the
United States. Sweden was the first to impose very strict west coast of Sweden, installed a hydrotreating facility that
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64 Petroleum Refining and Natural Gas Processing

25 160 ventional hydrotreating unit with moderate adjustments to

Gasoline
Middle Distillate
the operation parameters. Recent advances in higher activity
Other 140 catalysts also help in achieving a higher sulfur removal rate
20 Fuel Oil [72,73]. The second stage would require substantial modifica-
Cat. Hydro Refining & Treating
Cat. Reforming
120 tion of the desulfurization process, primarily through using
Cat. Cracking higher pressure, increasing hydrogen pressure, reducing
Coking+Thermal 100 space velocity, and choice of catalyst. Hydrogen consumption
Relative Increase

Relative Increase
15
Vacuum Dist. is the largest operating cost in hydrotreating, and minimizing
Crude Dist.
Cat. Hydrocracking
80 hydrogen use is a key objective in hydrotreating for sulfur
removal. In general, 10-ppm sulfur diesel would require
10
60 25–45 % more hydrogen consumption than would 500-ppm
sulfur diesel, in addition to improved catalysts. On the other
40 hand, removal of nitrogen or partial hydrogenation of aro-

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
5 matic rings before deep desulfurization are also possible
20 for removal of refractory sulfur compounds in a more cost-
effective way than hydrogenation.
0 0
2000 2001 2002 2003 2004
Year 3.5.2.3 Synthetic Diesel
Figure 3.54—Relative increase in world refining capacity and 3.5.2.3.1 Gas-to-Liquid Technologies (Fischer–Tropsch
product demand between 2000 and 2004 (year 2000 is taken Synthesis)
as base) [4]. High-quality diesel fuel (high cetane and low sulfur) can
be synthesized by a Fischer–Tropsch (FT) reaction [61,64].
is based on SynTechnology. Therefore, hydroprocessing has Gas-to-liquid (GTL) technologies potentially offer a supply
been far and away the most significant processing investment of very-high-quality middle distillates, particularly when
over the past few years [65]. It is generally believed that a two- demand for diesel fuel and jet kerosene is forecasted to grow
stage deep desulfurization process will be required by most, strongly with increasingly stringent quality specifications.
if not all, refiners to achieve a diesel product with less than GTL facilities have been operated commercially in recent
10 ppm sulfur. In some cases the first stage could be a con- years, including the Moss gas plant in South Africa with

D
/LJKW&XW
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9HKLFOHV
00ESG00ESG

Figure 3.55—Refining issue: (a) World market trend of petroleum products, (b) worldwide middle distillate demand distribution
of on-road fuel in 2008, and (c) projected demand for 2020.
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Chapter 3 n Worldwide Statistical Data 65

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Figure 3.56—Regional consumption of refined products (2008) and their distribution in different regions [13].

an output capacity of 23,000 bbl/day and the Shell Bintulu and its potential to reduce our dependence on petroleum
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

plant in Malaysia with an output capacity of approximately oil. It has also been established that exhaust emissions from
12,500 bbl/day. Natural gas GTL technology can be cost- biodiesel are substantially less than those from petroleum-
competitive only if investors are confident that crude-oil based diesel, which would reduce emissions [particulate
prices will stay in the low range. The focus of GTL technol- matter (PM), carbon monoxide (CO), and hydrocarbons]
ogy is to develop a clean viable route to make liquid trans- up to 75 %; however, oxides of nitrogen (NOx) emissions
portation fuels from natural gas and carbon dioxide. are slightly increased in the case of biodiesel [4,13,57]. Fig-
ure 3.57 indicates the chronological development (from 2000
3.5.2.3.2 Biodiesel to 2008) in world biofuel production and consumption. Bio-
Considerable interest has recently been focused on the fuel production and consumption increased approximately
further development and expansion of a domestic biofu- 7-fold from 300,000 bbl/day in 2000 to at least 1,500,000 bbl/
els industry. The reasons for growing interest in biodiesel day in 2008 (Figure 3.57a). The regional distribution of bio-
include its potential for reducing noxious emissions, its fuel consumption showed dramatic changes, particularly in
potential contributions to rural economic development as North America, the leading region since 2005, where capac-
an additional demand center for agricultural commodities, ity increased by 15 times (Figure 3.57, b and c). Table 3.10
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66 Petroleum Refining and Natural Gas Processing

indicates the top 10 countries for biofuel production in the continue fossil fuel-based energy development. Natural gas is
last decade. Apart from these countries, no other countries often described as the cleanest fossil fuel, producing less CO2
produce an excess amount of biofuel for commercial export. per joule delivered than coal or oil and far fewer pollutants
than other fossil fuels, as shown in Figure 3.58c. However,
3.5.2.3.3 Natural Gas as Transportation Fuel it does contribute substantially to global carbon emissions,
Promoting sustainable development and combating climate and this contribution is projected to grow with its use.
change have become integral aspects of energy planning. Natural gas can be used as automobile fuel in the form of
The level and growth of CO2 emissions (Figure 3.58a) and compressed natural gas (CNG) as an alternative to gasoline
their source and geographic distribution (Figure 3.58b) will and diesel. In addition, the energy efficiency of using natural
be essential to lay the foundation for a global agreement and gas (octane number of 120–130) is equal to that of gasoline

D

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Figure 3.57—Advances in alternative fuel (biofuel) and (a) their per-day world total production and consumption and regional
consumption in (b) 2000 and (c) 2008 [13].

Table 3.10—Biofuel Consumption Variation with Time and Top 10 Countries That Have High
Capacity to Consume Biofuel [13]
Total Biofuel Consumption (thousand bbl/day)

Rank Country 2000 Country 2005 Country 2008

1 Brazil 166.9 United States 270.7 United States 656.8

2 France 8.0 Brazil 182.0 Brazil 355.1

3 Germany 4.9 Germany 44.4 Germany 68.1

4 Canada 4.5 China 21.5 France 56.5

5 India 2.9 France 9.5 China 37.5

6 Spain 1.6 Spain 7.1 Canada 25.8

7 Czech Republic 1.4 Canada 6.0 United Kingdom 18.7

8 Cuba 1.1 Sweden 5.1 Spain 15.5

9 Malawi 0.2 Italy 4.1 Thailand 12.9

10 Argentina 0.1 India 3.9 Italy 12.5

AST-MNL58-11-0801-003.indd 66 3/12/13 12:47 PM

Chapter 3 n Worldwide Statistical Data 67

(a) 31000 (b)

North America Africa
Middle East
23% (25%) 4% (4%)

CO2 emissions, Million Metric Tons

6% (5%)
30000 Eurasia
9% (9%)

29000 Central &

(MMTs) South America
4% (4%)
28000

27000

26000 Asia &

Europe Oceania
15% (17%) 39% (36%)
25000
2004 2005 2006 2007 2008
Year

11000
CO2 emisssions, MMTs

Petroleum
10000

9000

8000

7000 Natural Gas

6000

5000
2003 2004 2005 2006 2007 2008 2009
Year
Figure 3.58—(a) CO2 emission by using fossil fuel, (b) 2008 regional distribution (data for 2004), and (c) effect of type of fossil fuel
on CO2 production [13].

sulfur levels, aromatic contents, and other fuel param-

&RXQWULHV1R9HKLFOHV eters. However there are no precise correlations between
1DWXUDO*DV9HKLFOHV0LOOLRQ

3DNLVWDQ price and properties. Fuel quality recently changed, mainly

$UJHQWLQD because of environmental issues. For example, in the EU,
%UD]LO the diesel sulfur level was 350 ppm in 2004, but by 2008
,UDQ a significant portion of diesel contained only 10 ppm
,QGLD sulfur and the rest was 5 ppm sulfur. Sulfur removal adds
to the cost of refining; therefore, comparison of diesel
prices in Europe between 2004 and 2008 reflects more
than oil price increases during the intervening years. How-
ever, 2008 was a dramatic year in which prices reached a
maximum limit ($148/bbl, July 2008) and dropped rapidly
with a record margin at the end of year ($35/bbl, Decem-
ber 2008).
<HDU Nevertheless, as every driver knows, filling up your
tank can be an expensive task. What is not generally
Figure 3.59—Worldwide natural gas vehicles used and top five
known is just where most of that money goes. Figure 3.60
countries (inset) that use natural gas vehicles.
attempts to shed some light on this issue and indicates a
wide regional variation in the prices (U.S. $/L) of different
engines but is lower than that of modern diesel engines.
oil products for 2008. However, these price variations are
Worldwide, approximately 9.6 million natural gas vehicles
not due to differences in crude-oil prices, but to varying
were running in 2009, mostly led top user as shown in Figure
levels of taxation in the major consuming nations. The fig-
3.59. In addition to displacing petroleum fuels with natural
ure shows how much of the price for each liter of oil goes
gas, one of the primary benefits is the potential to reduce
to oil producers (including cost of production and other
exhaust emissions of harmful pollutants such as SOx, NOx,
related expenses), the industry margin (includes transport,
and PM. Studies have shown that NOx reductions of 50–80 %
insurance, and other costs), and the amount that goes to
and PM reductions of 80–95 % are possible when heavy-duty
national government taxes. The graph indicates that tax
vehicles are operated on natural gas instead of diesel fuel.
levels range from relatively low levels in the United States
to very high levels in many EU countries. In the United
3.5.2.4 Refining Costs and Profits Kingdom, the government generates considerably more
The price variation in refined petroleum products mainly --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
money from taxation than OPEC member countries receive
depends on fuel qualities such as octane or cetane numbers,
Copyright ASTM International
from the sale of their oil. Thus, it is clear that the real cost
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68 Petroleum Refining and Natural Gas Processing

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Figure 3.60—Price of a liter of oil in different countries and the percentage of money that contributes to total market price [70].

burden on end-users is from the oil taxes imposed on cus- countries instead of just a crude-oil supplier. Thus, in the
tomers by their government. near future, most refinery capacity expansion is expected
to come from Asia and the Middle East by adding new
3.5.2.5 Regional Refinery Background and expanding existing refineries to meet the anticipated
and Their Capacities market demand in the region. In fact, the net Asian refin-
The worldwide cumulative refining capacity expansion is ing capacity increased approximately 1 million bbl/day
expected to contribute approximately 44 % to global refin- for 2009, followed by North America with more than
ing capacity additions during 2012–2015. The Middle East 0.393 million bbl/day and the Middle East with more than
and India plan to transform themselves into major refining 0.200 million bbl/day.
and petroleum product exporting-importing hubs, whereas Overall, it is expected that at the end of 2020, refinery
Central and South America are expanding their refining capacity worldwide will increase from 84.6 million bbl/day
capacity, mainly to process their domestic heavy crude oil, to 102 million bbl/day. At the same time, demand for crude
the production of which is rapidly increasing. However, oil is expected to increase from 82.6 million bbl/day in 2004
refining margins will remain modest because the demand to 90.4 million bbl/day. Thus, refinery capacity is 9.3 million
for products in the major consuming markets is expected to bbl/day whereas demand is approximately 7.8 million bbl/
remain low. A new trend is approaching that the national day. The United States has been operating their refineries at
oil companies (majority) are adding refining capacities— approximately 90 % capacity since 1992, which has a nega-
either to supply to the domestic refined products need or tive effect on the economy. The world is currently operating
to transform their countries into global refining hubs. For at close to 88 % capacity for refineries.
example, national oil companies in the Middle East are
investing in refineries to process domestic heavy crude 3.5.2.6 Refining in Africa
oil and reduce the import of light and middle distillates. In Africa before 1954 there were no refineries. After 50
Considering the regulatory constraints to build green-field years (2005), approximately 48 refineries were built in
refineries in North America and Europe, the Middle East Africa. The foremost African refineries were built in 1954
can become a major petroleum product supplier to these in Algiers (CFP/Total) and Durban (Socony/Mobil). These
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Chapter 3 n Worldwide Statistical Data 69

were followed by the building of the Luanda refinery capacity of existing ones to attain production of cleaner fuel
(Petrofina) in 1958 and refineries in Kenya (Shell/BP), with market demand.
Ghana (ENI/Agip), and Senegal (consortium) in 1963. The Middle East currently operates approximately 44
In the 1960s, refineries were also built in Cote d’Ivoire, refineries for crude-oil distillation (7.2 million bbl/day),
Gabon, Tanzania, Nigeria (Port Harcourt I), and Cape- vacuum distillation (1.9 million bbl/day), catalytic crack-
town. In the 1970s and 1980s, after nationalization of the ing (0.35 million bbl/day), catalytic reforming (0.65 mil-
oil industry in many countries, several state-controlled lion bbl/day), hydrocracking (0.59 million bbl/day), and
refineries were built. In the last decade, there have been hydrotreating (2.0 million bbl/day). Refining markets in the
several modernization projects, but the only new refineries Middle East are mainly controlled by the Gulf Cooperation
built in the past 10 years have been Khartoum in 2001 and Council (GCC), which offers comprehensive information
MIDOR in Egypt in 2002. Apart from the refineries, there on the refining markets in Saudi Arabia (eight refineries),
are also three synfuel plants (coal and gas feedstock) in the United Arab Emirates (three refineries), Kuwait (three
South Africa. The total active distillation capacity for the refineries), Qatar (one refinery), Oman (one refinery), and
continent is approximately 3 million bbl/day, an average of Bahrain (one refinery). GCC refining capacity increased
79,000 bbl/day per refinery. The major refining capacities from 1.7 million bbl/day in 1980 to 3.1 million bbl/day in
in Africa are in South Africa, Nigeria, Egypt, and Algeria. 1995, which was further targeted to 4 million bbl/day by
The largest refinery in Africa is the Skikda refinery in 2010. The cumulative refining capacity of these countries
Algeria (300,000 bbl/day), whereas the second largest is the accounted for 4.9 % of the global refining capacity and 41 %
Ras Lanuf plant in Libya (220,000 bbl/day). The African of the total refining capacity of the Middle East in 2008.
oil refining industry has been impacted seriously because New refineries and expansion in existing refineries will
of the poor management of the political situation during increase the refining capacity in the GCC to 6.8 million bbl/
recent years, and production has been an average of 65 % day by 2013, and GCC will contribute 6.4 % to the global
below capacity. refining capacity. The average size of refineries in the GCC
countries at 11.4 million metric tons per annum (MMTPA)
3.5.2.7 Refining in the Middle East is above the global average of 6.7 MMTPA.
The name “Middle East” has been associated with oil refin-
ing since the middle of the last century, and oil has been 3.5.2.8 Refining in North America
the backbone of the economy in this region for the past, In petroleum refining, North America, in particular the
present, and possibly for many decades to come. The region United States, plays an important role because it is the first
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

produces approximately two thirds of the world’s oil con- to import and export petroleum. Moreover, North America
sumption, whereas Middle Eastern natural gas reserves are has approximately 200 petroleum refineries within North
approximately one tenth of the world’s proven reserves as and South America, including 600 defined areas and over
of January 1, 2009 [13]. The economy of oil-producing 3900 operating units. Most of the units have distillation,
countries in the Middle East/North Africa region heav- whereas others have just downstream processes such as
ily (80–90 %) depends on oil revenues, yet some 70 % of fluid catalytic cracking, hydrotreaters, reforming, thermal
businessmen in this region do not consider environmental cracking, etc. The United States has approximately 108
issues in their business practices. The main areas of refin- refineries, Canada has approximately 26 refineries at differ-
ery capacity in the Middle East are reported in Figure 3.61, ent places, and Mexico has 6 refineries (~1.5 million-bbl/day
indicating saturation in the process operations. Middle capacity), all of which are controlled by PEMEX (Petróleos
Eastern countries are also thinking of enhancing total refin- Mexico). However, Mexico exports a huge amount of crude
ing capacity by 2015 for downstream refining capacity at oil, but it imports expensive gasoline from U.S. refineries.
home as well as abroad. The new capacity plan is mainly Thus, adequate planning and investments available for
in the area of distillation and hydrotreating. Major plans refining capacity are required to set up a new refinery and
are underway to construct new refineries and increase the revamp their existing refineries. North American refinery

D E

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5HILQLQJ&DSDFLW\7KRXVDQGVEEOFG

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&DW&UDFNLQJ
7KHUPDO
5HIRUPLQJ
&UXGH'LVW
&UXGH'LVWLOODWLRQ

<HDU

Figure 3.61—Middle Eastern refinery capacity variation since 2000 and its distribution [13].
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AST-MNL58-11-0801-003.indd 69 3/12/13 12:47 PM

70 Petroleum Refining and Natural Gas Processing

capacity of crude-oil distillation is at approximately 16 mil- 3.5.2.9 Refining in South America

lion bbl/day of operable capacity. The new capacities are The total number of refineries available and their operating
coming up mostly with hydrotreating to meet the tighter capacity for South America are reported in Table 3.11. The
product specifications. Therefore, expansion of refining table indicates that Petroleos de Venezuela (PdVSA) and
capacity in North America will primarily be through addi- Petrobras are the two main refining components in South
tion of secondary conversion units. Recent U.S. refineries’ America, and they have domestic and foreign interests.
capacity for various processes and the variation of capacity PdVSA operates one of the largest refineries (940,000 bbl/
in recent years are shown in Figure 3.62. Figure 3.62 indi- day) at the Paraguana refining complex. Domestic refinery
cates that, except for hydrotreating, North America’s refin- capacity stands at 1.28 million bbl/day, whereas its overall
ing capacity remained virtually flat. In the United States, crude-oil refinery capacity is over 3 million bbl/day when
ConocoPhillips (2.22 million bbl/day), Valero (2.20 million including the Caribbean, United States, and Europe. One
bbl/day), and ExxonMobil (2.06 million bbl/day) own the third of Venezuela’s refined product is exported to U.S.
top-most positions. In late 2009, Marathon Oil Corpora- markets, particularly for reformulated gasoline, which is
tion completed an expansion in Garyville, LA, and started a distributed mainly by the Tulsa-based Citgo Corporation.
refinery in early 2010 with the capacity of 180,000 bbl/day. PdVSA has been looking for partners to increase the com-
Apart from this, Saudi Arabia and Kuwait have made offers pany’s ability to refine Venezuela’s heavy and extra-heavy
to build new refineries in the United States because the big crude to increase production in coming years. PdVSA
oil companies have not stepped up to the plate. currently has two main refining joint ventures in Europe:
AB Nynäs Petroleum (Sweden) and Ruhr Oel GmBH
(Germany). The partnership gives PdVSA access to five
refineries in Europe. In addition, regional oil industry inter-

nationalization strategic (energy integration and corporate)
7RWDO

alliances are under discussion, the enterprises of which
may have significant effects on the economic and energy
7RWDO7KRXVDQGVEEOGD\

integration processes in South America. The international-
7KRXVDQGVEEOGD\

+\GURWUHDWLQJ+'6 ization of the oil markets in this region have occurred with
the arrival of major companies (Exxon-Mobil, Chevron-

&DWDO\WLF&UDFNLQJ
Texaco, and Shell), and more particularly the companies
established through the privatization of European state-

&DWDO\WLF5HIRUPLQJ
run enterprises (Repsol-YPF, ENI-Agip, Elf-Total-Fina, and
British Petroleum-Amoco) [74].
7KHUPDO&UDFNLQJ

+\GURFUDFNLQJ 3.5.2.10 Refining in Europe

The European (EU) refining industries are facing a tough
slog of market conditions because of their new regulatory
<HDU
commitment and inclusion of biofuel. The petroleum refin-
Figure 3.62—U.S. refineries’ capacity for various processes and ing industry is a key sector in the EU framework facing
its variation in recent years [13]. the foremost challenges. These include supply and demand

Table 3.11—South America Refineries and Their Capacity

Oil Refining Profiles

Country Number of Refineries Total Capacity (bbl/day) Comments

Venezuela 6 3 million Domestic six-refinery capacity stands at 1.28 million bbl/day

Brazil 13 2 million 98 % of refineries (10) are controlled by Petrobras; plans to build a

new refinery with a capacity of 200,000 bbl/day

Chile 3 194,990 Controlled by ENAP (merger of Petrox and Biobio). New refinery at
Biobio that will be able to produce diesel with low S content
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Peru 2–4 192,950 Repsol (two refineries) controls the largest facility in the country,
whereas the other four refineries are controlled by Petroperu

Ecuador 3 176,000 Ecuador has one of South America’s largest markets for LPG

Argentina 3 82,000 Repsol accounts for approximately half of the country’s total crude-oil
refining capacity; Shell and Esso also share small part

Bolivia 5 67,000 Petrobras operates through its affiliate Empresa Boliviano de

Refinación (EBR)

Suriname 1 – Staatsoile’s refinery

Data compiled from several sources.

Copyright ASTM International

AST-MNL58-11-0801-003.indd 70 3/12/13 12:47 PM

Chapter 3 n Worldwide Statistical Data 71

imbalances, flat demand, expected low margin, and com- world. In this region, two major countries (China and India)
petition from other regions. Because of the legislation in play a leading role in petroleum consumption with their
fuel, Europe faces a major supply and demand imbalance enormous populations. The demand is increasing particu-
because it is importing approximately 27 million t of middle larly for middle distillate or transportation fuel. Moreover,
distillate from Russia and exporting 31 million t of gas to most countries (except China) in this region have a lack of
the United States. Europe has been most impacted by fall- petroleum supply and must rely on crude-oil import. The
ing demand in 2009, which is not forecast to recover quickly. world’s top refineries are installed (Reliance I and II, India),
Moreover, growing interest in biofuel will further depress and they have the capacity to process approximately 1.24
oil product demand. New European capacity is primarily million bbl/day. This refinery has a huge processing capac-
hydrocracking units, and some coking is expected in 2010, ity, particularly of crude oil that has a very high amount of
particularly in Spain. In addition, because of an increasing bottom-of-barrel. Petroleum Intelligence Weekly reports that
number of vehicles using diesel fuel, the largest amounts of nearly 1.8 million bbl/day of new refining capacity is slated
gasoil are imported by France, Germany, and Spain. France in 2012, a 59 % increase in India’s current processing capac-
has diversified its import sources (Russia, 18 %; the United ity (~3 million bbl/day). The domestic product demand of
Kingdom, Italy and Germany, 11 % each), Germany imports 2.24 million bbl/day is forecast to increase by 2.9 % to 4.5 %
over half of its diesel from the Netherlands, whereas Spain over the period 2010–2015. India’s refiners are looking at
imports close to 40 % of its imports from Italy. The main increasing refined product exports to the Middle East, par-
gasoline exporter is the Netherlands, exporting more than ticularly Iran, the Asia-Pacific region, Europe, and Latin
twice the amount of the second exporter (United Kingdom). America. It is expected that approximately 76 % refining
The Netherlands supplies most of its high-specification capacity will be added in China and 15 % in India. Thus,
surplus to Germany, followed by Belgium and the United China’s capacity will reach more than 15 million bbl/day
States. Germany also acts as a major gasoline supplier to by 2020, and India’s capacity will overtake that of Japan by
Switzerland, the United States, and Austria. 2012 to become the second-largest refiner in Asia.
In Europe, refineries are found in most countries other Within 12 Asian countries, approximately 145 refin-
than Luxembourg, and there are areas in Europe where eries operate at approximately 84 % refinery capacity.
there are multiple refineries at the same location (e.g., Rot- The major problem in Asian refineries is that out of 145
terdam and Antwerp). In 2004, approximately 104 refiner- refineries, 113 do not have hydrotreating or hydrocracking
ies were in operation in 27 EU countries, and their total capacity. Within this, 15 have hydrotreating unit capacity
refinery breakdown is shown in Figure 3.63 along with the only in the 8–10 % range, whereas 9 have hydrocracking
most important processes. The EU refining industry con- units working with capacity in the 12–30 % range. Only
tinues investment to meet increasingly stringent emission five refineries have hydrotreating and hydrocracking units
standards. European refiners have invested an average of with a total capacity of approximately 25 %. Therefore,
$6 billion each year over the past 20 years in desulfurization significant investment is required to meet Euro III or Euro
capacity of distillates and gasoline, the upgrading of produc- IV type transportation fuel across the region. Several new
tion facilities, emission abatement equipment, and energy refineries are to be built in Asia over the next 5 years,
savings. EU overall demand for refined products is on a particularly in China and India, whereas more developed
downward trend. However, trends vary for different types nations are upgrading their existing facilities to meet
of refined products, but overall, the expected representation stricter fuel standards. A total account of Asian refinery
is of a 20 % drop in demand by 2030 compared with 2006. structure by country along with percentage capacity is
reported in Table 3.12. China and India will continue to
3.5.2.11 Refining in Asia account for the many major projects to build new refiner-
In the Asian region, demand and supply have recently ies or upgrade existing ones. China (Sinopec, 50 %) plans
changed in a wider spectrum than any other part of the to work in a joint venture with Kuwait (KPC, 50 %) to set
up their alliance in Guangdong province. China’s largest
oil company (PetroChina Company) recently started its
7RWDO5HILQHULHVLQ2SHUDWLRQ 6LPSOH new 20,000-bbl/day refinery at the port city of Qinzhou,
5HILQHU\%UHDNGRZQE\7HFKQRORJ\

6LPSOH 9LVEUHDNHU having a 70,000-bbl/day heavy residue catalytic cracker, a

&DW&UDFNLQJ 44,000-bbl/day hydrocracking unit, and a 44,000-bbl/day
&DW&UDFNLQJ &RNHU continuous reforming unit. On the other side, HPCL, India
+\GURFUDFNLQJ upgraded (mainly for ULSD) its two refineries to meet the

+\GURFUDFNLQJ &RNHU Euro IV emission standard. Overall, in 2009 Asia added 2.2
%RWK&& +& million bbl/day of refining capacity, the largest distillation
%RWK&& +& &RNHU capacity addition in the region’s history. In 2010, estimated
demand in the Asia-Pacific region grew strongly at 1.1
million bbl/day, whereas net refining capacity additions
reached only 820,000 bbl/day.

3.5.2.12 Refinery Impacts on GHG Emissions
(Environmental Issue)
In general, petroleum refining is a capital-intensive busi-
5HILQHU\3URFHVVHV
ness that must conform to the stringent environmental
Figure 3.63—2004 refinery breakdown in Europe by technol- regulations of the processing industry and deal with
ogy [13]. declining refining margins, political instability, increasing
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Copyright ASTM International

AST-MNL58-11-0801-003.indd 71 3/12/13 12:47 PM

72 Petroleum Refining and Natural Gas Processing

Table 3.12—Asian Refinery Structure by Country in Percent Capacity

Number of Thermal Catalytic
Country Refineries Cracking Coking Cracking Hydrocracking Hydrotreating

China 47 – 6.7 20.5 2.8 1.1

Japan 29 – – – – –

India 19 4.4 2.1 7.9 2.6 3.8

Indonesia 10 5.9 3.3 10.2 10 1.2

Thailand 7 2.6 – 11.8 2.9 14.3

Malaysia 6 – 3.7 – 5.5 6.1

Pakistan 6 – – – – –

South Korea 5 – – – – –

Singapore 3 16.4 – 5.1 7.4 20.7

Philippines 3 5.2 – 5.8 – 23.7

Burma 3 – – – – –

Myanmar 2 – 16.3 – – –

Brunei 1 – – – – –

Bangladesh 1 30.3 – – 3.6 –

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Sri Lanka 1 26.7 – – – 4.2
Data collected compiled from several sources.

risk of war, and terrorist attacks. Higher pressures have feedstocks requires improvements in the control of the indi-
recently been exerted on refiners to optimize performance vidual reactions, better management of hydrogen, and more
and find the best combination of feed and processes to selective removal of heteroatoms. Development of a next
produce stable products that meet the stricter product generation of catalysts and processes for heavy feedstocks
specifications. For example, an increase in desulfurization requires molecular-scale understanding of the crude com-
will result in increased refinery GHG emissions, but these ponents, including the interactions between large, complex
increases are required to achieve near-zero-sulfur transpor- molecules such as asphaltene, resin, metal-porphyrines, etc.
tation fuel. The production of low-sulfur fuels is generally Since petroleum is composed of complex hydrocarbon mix-
more energy-intensive, often requiring higher temperatures tures, it is not easy to identify each individual component
and pressures and more hydrogen consumption. Moreover, and its catalytic reaction chemistry. Therefore, it is desir-
the hydrocarbons conversion process is extremely CO2- able to understand what the feedstocks components are,
intensive, creating 8–15 t of CO2 for every ton of hydro- how they interact with catalysts, how partial conversions
gen used [75]. In addition, removal of sulfur from diesel (such as hydrogenation) affect the reactant species and
(350–50 ppm) results in an approximately 3 % increase in their interactions, and how construction of the aggregates
refinery emissions. To get to even lower sulfur levels (50–10 takes place and affects the reactivities of the molecules.
ppm), CO2 emissions were increased by an additional 4.3 %
for gasoline refining and 1.8 % for diesel. The literature 3.5.3 Worldwide Natural Gas Conversion and
data suggested that the total impact on refinery emissions Liquefaction Plants
for production of gasoline and diesel at 10 ppm sulfur 3.5.3.1 Natural Gas Overview
would be worse than additive, with a 12.9 % increase in CO2 Figure 3.65 shows the latest assessment of natural gas as a
emissions to achieve 10 ppm sulfur diesel and gasoline [76]. function of regional distribution. The top consumer of nat-
ural gas is the United States. The natural gas consumption
3.5.2.13 Role of Catalytic Conversion in the non-OECD countries grows more than twice as fast
and Refinery Capacity as in the OECD countries. Production increases in the non-
In refining, catalysis has undoubtedly played a very impor- OECD region account for more than 80 % of the growth in
tant role since the mid-20th century and the development world production. The worldwide demand (consumption)
of the refining and petrochemical industries. Some limited is gradually increasing, particularly in Europe, the Middle
but important dates are reported in Figure 3.64, indicating East, and Asia, whereas in North America and Africa its
the catalyst development and the catalyst type used in the growth remains constant, as shown in Figure 3.66.
refinery [59]. The mounting concerns over the environment Natural gas generally contains 70–90 % methane at
and the growing need to process heavier/dirtier crude oils its natural source point. The balance of the gas is usu-
will make it mandatory to develop new catalysts for produc- ally ethane, propane, butane, water, nitrogen, CO2, and
ing high-quality, ultraclean fuels. Thus, new refining goals hydrogen sulfide (H2S). Natural gas from different wells
are emerging. The efficient economical conversion of these is widely different in composition. The main undesirable
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Chapter 3 n Worldwide Statistical Data 73

Deep HDS of
Etherification gasoline & Diesel

RCC & HDS of

FCC gasoline
Consumption Bimetallic
reforming
Consumption 1999
Zeolites
in HDC
1.0
Zeolites
in FCC

HDC
0.8
Pt-Reforming Refining
0.6 FCC & CCR
Alkylation reforming

Isomerization Catalytic
Hydrotreating dewaxing
0.4 Cat. cracking &
Oligomerization Automotive
converters
Continuous
Batch distillation Isodewaxing
0.2
distillation

0.0
1850 1900 1950 2000
CH3OH Steam
synthesis reforming
of CH4

Arom.
Zeolites in
Petrochemicals
Bifunction
Alkylation
Ag isom Ag isom.

Fischer- Selective Zeolites in

Tropsch hydrogenation Arom, Alkylation

Figure 3.64—Some important dates in the development of the refining and petrochemical industries. Alkyl, alkylation; A8, C8
aromatics; Arom., aromatics; Bifunct., bifunctional; CCR, continuous catalyst regeneration; FCC, fluid catalytic cracking; HDC,
hydrocracking; HDS, hydrodesulfurisation; RCC, residual catalytic cracking [59].

1RUWK$PHULFD

0LGGOH(DVW
*HRJUDSKLFDO5HJLRQ

(XURSH

(XUDVLD

&HQWUDO 6RXWK
$PHULFD 1DWXUDO*DV2YHUYLHZ
&RQVXPSWLRQ
$VLD 2FHDQLD ([SRUWV
,PSRUWV
$IULFD 3URGXFWLRQ

7ULOOLRQ&XELF)HHW

Figure 3.65—An overview of natural gas as a function of geographical region [13].

impurities are CO2 and H2S. The former does not need to be tion, usually with an amine-based solvent, although use of
completely removed, but the latter is highly poisonous and membranes to process natural gas is a rapidly growing area
needs to be removed to a concentration of less than 1 ppm. of technology.
The standard technology applied for removing natural gas After purification, natural gas is carried on-board as
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

contaminants is by saturation of natural gas into a solu- a cryogenic liquid (LNG) or in the form of high-pressure
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74 Petroleum Refining and Natural Gas Processing

1RUWK$PHULFD 6 &HQW$PHULFD 1DWXUDO*DV5DZ
(XURSH (XUDVLD 0LGGOH(DVW
$IULFD $VLD3DFLILF
%LOOLRQFXELFPHWHUV

&2 5HPRYDO
&RQGHQVDWH5HPRYDO
&2
3URFHVVLQJ
&OHDQLQJ
+6 +J
'HK\GUDWLRQ
5HPRYDO
+2 1*/
+6 +J

5HIULJHUDWLRQ
+HDYLHU+& 7HPS&
& RU& DWPSUHVVXUH

/LTXHIDFWLRQ

<HDU /1*

Figure 3.66—Natural gas consumption [13]. 6WRUDJH 7HPS&

/RDGLQJ 3UHVVN3D

compressed gas (CNG). Because LNG fuel tanks are much 7UDQVSRUWDWLRQ
more expensive than CNG tanks, vehicles usually carry 0DUNHWLQJ

natural gas fuel as CNG rather than as LNG. Thus, LNG

Figure 3.67—A typical integrated NGL and LNG processing
offers an energy density comparable to petrol and diesel plant in which the NGL and LNG are purified by removing any
fuels and produces less pollution, but its production is condensates such as water, oil, and mud as well as other gases
relatively higher cost and it must be stored in expensive such as CO2 and H2S and sometimes solids as such as mercury.
cryogenic tanks, which prevents its widespread use in com- The gas is then cooled down in stages (–35, –90, and –155°C)
mercial applications. A schematic flow diagram of natural until it is liquefied. LNG is finally stored in storage tanks and
gas liquid separation from its base components is shown can be loaded and shipped.
in Figure 3.67. The global LNG industry has seen dramatic
growth since the late 1990s. According to BP, global LNG
trade has increased from 113 million t/year (MMtpy) in pressure, and source gas composition, and purity require-
2000 to 154 MMtpy in 2006. The same source expects LNG ments must be considered. Primary amines are more effec-
trade to reach 524 MMtpy by 2030. In 2008, a combined tive at atmospheric pressure conditions, and MEA can
liquefaction capacity of 207.01 MMtpy was provided by 31 remove H2S to less than 4 ppm, but it is effective up to 100
terminals in 17 countries supplying LNG to 59 regasifica- ppm for CO2 removal. DGA is another primary amine that is
tion terminals with a combined capacity of 402.15 MMtpy typically used for the removal of CO2, H2S, carbonyl sulfide
in 19 countries [4]. (COS) gas, and mercaptanes. Secondary amines (e.g., DEA)
remove CO2 and H2S, but they generally require higher pres-
3.5.3.2 Natural Gas Processing sure than MEA to meet overhead specifications. Because
Natural gas processing refers to the removal of ethane, DEA is a weaker amine than MEA, it requires less energy for
propane, butane, and heavier components from a gas stripping. Tertiary amines such as MDEA are often used to
stream. Various conventional separation methods are pres- selectively remove H2S, especially for cases with high CO2-
ently being used to remove acid gases such as CO2 and H2S to-H2S ratios as in natural gas. MDEA can remove H2S to 4
from crude natural gas [77,78]. These methods include gas ppm but maintain 2 % or less CO2 in the treated gas using
absorption in liquid solvents, adsorption on solid adsor-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

relatively less energy for regeneration than that for DEA.

bents, and chemical conversion. Because MDEA is not prone to degradation, corrosion is
thus low and a reclaim is unnecessary. Operating pressure
3.5.3.2.1 Conventional Process for Natural can range from atmospheric (typical of a tail-gas-treating
Gas Processing unit) to over 70 bar. With mixed solvents, the solvent can be
The selective removal of impurities may depend on the adapted to optimize the sweetening process; for example,
acid-base reaction. The selection of the best amine/solvent adding a primary and secondary amine to MDEA can
for gas treating is not a trivial task. Amine gas treating, also increase the rate of CO2 absorption without compromising
known as gas sweetening and acid gas removal, refers to a the advantages of MDEA. Advantages of using such solvents
group of processes that uses aqueous solutions of various are usually increased mercaptane pickup, lower regenera-
alkylamines to remove H2S and CO2 from gases. There are tion energy, and selectivity to H2S. Apart from the amine, it
several amines available to remove contaminants such as is also possible to use solid desiccant (e.g., iron sponges) to
CO2, H2S, and organic sulfur compounds from sour gas remove the sulfide and CO2 from the natural gas.
streams, as shown in Figure 3.68. The most commonly used
amines are methanolamine (MEA), diethanolamine (DEA), 3.5.3.2.2 Membrane Separation Process for
methyldiethanolamine (MDEA), diglycolamine (DGA), Natural Gas Processing
diisopropanolamine (DIPA), and triethanolamine (TEA). A Membrane separation processes are a relatively new devel-
mixture of amines can also be used to customize or opti- opment over the last 2 decades as a promising alternative to
mize the acid gas recovery. However, selection of amine conventional separation processes and offer several impor-
composition and its type also depend on the temperature, tant advantages [78–80]. These membranes are made of
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Chapter 3 n Worldwide Statistical Data 75

Condenser (H2S + CO2)

Sweet gas
Acid gas

Makeup Reflux
water drum

Rich Reflux
Top Top
amine

amine
tray

Lean
tray
Pump
Absorber
Regenerator

Bottom Bottom
Sour Gas Vapor Steam
tray tray

Reboiler

Liquid
Rich
amine Lean Condensate
amine

Typical Operating Ranges Pump

Absorber: 35–50 °C and 5-205 atm of absolute pressure
Regenerator: 115–126 °C and 1.4–1.7 atm of absolute pressure at tower bottom

Figure 3.68—Process flow diagram of a typical amine sweetening unit used in industrial plants.

2+ 2+
2 ) & &) 2

1 1

Q
2 2

E
Figure 3.69—Type of natural gas separation membrane structure for selective removal of CO2: (A) fluorine-containing polyimide
6FDA-HAB-glassy polymer and H2S and (B) poly(ether urethane urea) (PEUU)-rubbery polymer [81].

polymeric-type materials, the structure of which is shown area or the increase of the pressure ratio (feed pressure
in Figure 3.69. Generally, polymer membranes are used to permeate pressure). Higher feed flow rates reduce the
commercially to separate CO2 and H2S from natural gas. purity but increase the permeate concentration of the
The membrane permeation is a pressure-driven process. faster-permeating compound. The upgrading of low-quality
The partial pressure difference between the feed side and natural gas by membrane separation processes has been
the permeate side has the greatest impact on the perfor- reported by simultaneously or separately operating two
mance of a membrane separator. This pressure difference different types of polymer membranes that exhibit high
directly influences the membrane area required to achieve CO2/methane (CH4) and H2S/CH4 selectivities along with
the desired separation at given feed conditions. Another process design, optimization, and economic assessment
important characteristic of the process is the ratio of feed studies [81].
pressure to permeate pressure, which has to be established
in accordance with the membrane selectivity to achieve an 3.5.3.3 Natural Gas Demand and Supply
efficient separation. The gas purity can be increased by the The natural gas sector has been a tight supply and demand
installation of more membrane (one stage or multistage) balance, with rising energy prices followed by demand
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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76 Petroleum Refining and Natural Gas Processing

weakening and spot-price plummeting. After a 1 % increase CO + H2O (syngas) + water shift reaction →
in 2008, OECD gas demand fell by 4 % during 2009 and CO2 + H2 (3.3)
2010. In the United States, natural gas demand increased
0.7 % in 2008 to 23.2 trillion ft3. Domestic natural gas In the past, coal was converted to make coal gas, which
production increased 7.7 % in 2008 over 2007, the largest was piped to customers to burn for illumination, heating,
increase since 1984. Demand for natural gas depends highly and cooking.
on the time of year and is highest during the winter and
lowest in the summer. 3.5.4.3 Coal Processing into Natural Gas
The natural gas cost of production is expected to be signifi-
cantly lower than current prices of new drilled natural gas
3.5.4 Worldwide Coal Conversion and and imported LNG that meets all high-grade, natural-gas-
Gasification-Liquefaction Plants quality specifications.
3.5.4.1 Coal Overview The hydromethanation process is an elegant and highly
Among the fossil fuels, natural gas is the cleanest whereas efficient process by which natural gas is produced through
coal is the most difficult hydrocarbon source. Coal is a the reaction of steam and carbonaceous solids in the pres-
hard, black-colored, rock-like substance. It is made up of ence of a catalyst. The process enables the conversion of
carbon, hydrogen, oxygen, nitrogen, and varying amounts low-cost feedstock such as coal, petroleum coke, and bio-
of sulfur. There are three main types of coal: anthracite mass into clean, high-purity CH4. The chemistry of catalytic
(hardest), bituminous, and lignite (softest). It is expected hydromethanation involves water steam and carbon to
that coal could become the dominant fuel by the middle produce CH4 and CO2.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

of the 21st century. Approximately 40 % of the global

electricity generated comes from coal. Coal is predomi- 2C + 2H2O → CH4 + CO2 (3.4)
nantly used by the electricity-generation sector, which
uses more than 3 times as much coal as other industries, Thus, hydromethanation is an economic and clean
particularly the steel industry. The use of coal has recently process for the production of natural gas by using an envi-
been growing faster than oil or gas use, particularly in ronmentally friendly process.
China and India. Therefore, the price of coal has gone up
approximately 1.5 times within the last 10 years ($30 per 3.6 Conclusions
short ton in 2000 to ~$150 per short ton as of September The main source of energy remains fossil fuel, which will
2008); however, at the end of 2008, the price per short ton continue for the next several decades. After this, the global
had declined to $111.5. The most important countries that economy will have to transition from oil to renewable
have more than two thirds of the world’s coal reserves are energy, such as solar, wind, ethanol, and hydrogen. The
China, Russia, the United States, and India [13]. China world continues with the current energy-related policies,
and India have plans to construct a new coal-fired plant, with heavier and complex crude-oil processing capacities.
whereas the United States generated approximately 150 Thus, refinery obligations are to enhance their capacity to
new plants in 2007. It is possible that coal’s prospects in convert black gold into usable consumer products, which
Europe are also currently undergoing some kind of resur- is essential for transforming crude into gasoline, diesel, or
gence, especially given the large reserves in the region’s household fuel. The refiners are facing two dimensional
biggest producer—Poland. Indeed, across the EU, 50 new problems: (1) the refining industry’s need for upgrading
coal-fired plants are being considered for construction capacity (i.e., upgrading oil from sour to sweeter crudes
over the next few years. rather than primary distillation capacity in refining); and
(2) most important are the increasingly tightening envi-
3.5.4.2 Coal Gasification and Liquefaction ronmental specifications on transportation fuels. High oil
Coal gasification can be used to produce syngas, a mixture prices are still being propped up by a shortage of refinery
of CO and hydrogen (H2) gas. This syngas can then be capacity, and there is little sign of the bottleneck easing at
converted into transportation fuels such as gasoline and the present time. For the coming decades, the use of heavy
diesel by using the FT process. During gasification, the coal and unconventional oils, natural gas, biofuel, and coal will
is mixed with oxygen and steam (water vapor) while also increase while in many parts of the world resources for
being heated and pressurized. During the reaction, oxygen conventional oil diminish. The Middle East will remain as
and water molecules oxidize the coal into CO and H2. This the main supplier of crude oil and natural gas for many
process has been conducted in underground coal mines and years to come. Toward the middle of the century, the use
in coal refineries. of renewable sources of energy will increase and refineries
should focus on providing feeds to petrochemical industries
(Coal) + O2 + H2O → H2 + CO (syngas) (3.1) rather than fuels for motor vehicles.

Acknowledgments
On the basis of refiner desire, the syngas is collected and The permission to use some graphs and charts by various
processed in a FT reaction for gasoline yield; if hydrogen is organizations is greatly appreciated. In particular, I am
the desired end product, then the syngas is fed into the water grateful to the Commonwealth Copyright Administration
gas shift reaction in which more hydrogen is liberated. of the Government of Australia, the Survey of Energy
Resources, World Energy, the EWG, Oxford Analytica, Ltd.,
CO + H2O (syngas) + FT reaction → the BP Economics Team, and the EIA of the U.S. Depart-
gasoline pool (liquefaction) (3.2) ment of Energy.
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Chapter 3 n Worldwide Statistical Data 77

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78 Petroleum Refining and Natural Gas Processing

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4
Properties, Specifications, and Quality of
Crude Oil and Petroleum Products
M.R. Riazi1 and Semih Eser2

Abbreviations (IBP) to a final boiling point (FBP) or end point (EP) when
API American Petroleum Institute the highest-boiling compounds evaporate. Measurement of
CH Carbon to hydrogen weight ratio FBP is not very accurate and usually boiling points at 95
CR Carbon residue vol % distilled are reported. The difference between FBP
CN Cetane number and IBP is called the “boiling range,” and for crude oils this
DAO Deasphalted oil difference may exceed 1000 °F (> 550 °C). For petroleum
EP End point (same as FBP) products the boiling range may vary from 25 °C for narrow
FBP Final boiling point boiling range to 200 °C for wide boiling range fractions [1].
FVI Fuel volatility index The simplest method of measuring boiling point of
GC Gas chromatography petroleum fractions is by the ASTM D86 method, in which
IBP Initial boiling point boiling points are measured at 10, 30, 50, 70, and 90 vol
IP Institute of Petroleum (UK Petroleum Standards) % vaporized samples of 100 cm3. In many cases boiling
ISO International Organization of Standards points at 0, 5, and 95 % are also reported. For tempera-
LC Liquid chromatography tures reported in the ASTM D86 method in which they are
MS Mass spectrometry above 250 °C (480 °F), correction because of cracking may
PNA Paraffins, naphthenes, and aromatics content of a be needed [2]. Although the ASTM method is very simple
petroleum mixture and convenient, it is not consistent or reproducible. As an
RVP Reid vapor pressure alternative method, distillation data can be obtained by gas
SD Simulated distillation chromatography (GC), in which boiling points are reported
SEC Size exclusion chromatography versus the weight percent of sample vaporized. This test
SG Specific gravity method described in ASTM D2887 is also called simulated
SUS Saybolt universal second distillation (SD). This method is applicable to petroleum
TBP True boiling point fractions with FBPs of less than 538 °C (1000 °F) and a boil-
TCD Thermal conductivity detector ing range greater than 55 °C (100 °F). It is not applicable to
TVP True vapor pressure gasoline.
ULSD Ultra low sulfur diesel SD curves are very close to actual boiling points known
UOP Universal oil products as true boiling points (TBPs). TBP curves are determined
VGC Viscosity gravity constant by distillation of sample in a distillation column with
15–100 theoretical plates and relatively high reflux ratio
4.1 Boiling Point and Distillation Data (i.e., ~1–5). The IBP of a TBP curve is less than the IBP
The boiling point of a pure compound is the temperature from ASTM D86, whereas the FBP by a distillation curve
at which vapor and liquid exist together at equilibrium. is greater than that of ASTM D86. In the TBP curve the
Boiling point varies with pressure, and the temperature at IBP is the vapor temperature that is observed at the instant
which a liquid’s vapor pressure equals 1 atm is called the that the first drop of condensate falls from the condenser.
“normal boiling point” or simply the “boiling point.” The Details of various distillations curves and their interconver-
boiling point decreases with decreasing pressure. The boil- sions are discussed in ASTM Manual 50 [2].
ing point of pure hydrocarbons increases with the increas- The newest methods for determining boiling points of
ing carbon number and molecular weight. Naphthenic heavy hydrocarbons and heavy oils by SD are described in
and aromatic compounds have higher boiling points than ASTM D6352 and D7169, which are widely used because the
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

those of paraffins with the same carbon number. Boiling instruments are finally robust and cost-competitive. It is pos-
points of heavy hydrocarbons are usually measured at low sible to determine boiling points of heavy oil up to C100 [3].
pressures (i.e., 1, 10, and 50 mmHg) and reported as atmo- Normal boiling points of n-alkanes up to n-C100 as given in
spheric pressure equivalent boiling points because at these ASTM D6352 [4] are shown in Figure 4.1, indicating that the
temperatures they may go through thermal decomposition. boiling point approaches a finite value for very heavy hydro-
Whereas for pure compounds the boiling point is a sin- carbons. These data are consistent with predicted values
gle temperature, for mixtures such as petroleum products from methods described in ASTM Manual 50 for the boiling
the boiling point covers a range from initial boiling point points of heavy hydrocarbons [2].
1
Kuwait University, Kuwait
2
The Pennsylvania State University, University Park, PA, USA
79
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80 Petroleum Refining and Natural Gas Processing

Liquid hydrocarbons with lower SGs have higher API

gravities. Aromatic hydrocarbons have higher SG (lower
API gravity) than paraffinic hydrocarbons. For example,
benzene has a SG of 0.8832 (API of 28.72) whereas n-hexane
with the same carbon number has a SG of 0.6651 (API grav-
ity of 81.25). A liquid with SG of 1 has an API gravity of 10.
The definition of SG for gases is somewhat different. It
is defined as the relative density of gas to the density of air at
standard conditions. In addition, the density of gases is a strong
function of pressure. Because at standard conditions (15.5 °C
and 1 atm) the density of gases is estimated from the ideal
gas law, the gas SG is proportional to the ratio of the molecu-
lar weight of gas (Mg) to the molecular weight of air (28.97).

Mg (4.4)
SGg =
28.97
Therefore, to obtain the SG of a gas, only its molecular
Figure 4.1—Normal boiling point of n-alkanes: Data taken weight is needed.
from ASTM D6352 [4].
4.3 Molecular Weight
Molecular weight is another bulk property that is indica-
tive of molecular size and structure. This is an important
4.2 Density, Specific Gravity, and API Degree property that laboratories usually do not measure and fail
Density is defined as mass per unit volume of a fluid. to report when reporting various properties of petroleum
Liquid densities decrease as temperature increases, but fractions. This is perhaps because of the low accuracy in
the effect of pressure on liquid densities at moderate pres- the measurement of the molecular weight of petroleum
sures is usually negligible. The density of petroleum frac- fractions, especially for heavy fractions. However, it should
tions is measured at 15.5 °C (60 °F) or 20 °C (68 °F) and at be realized that the experimental uncertainty in reported
atmospheric pressure. Liquid density for hydrocarbons is values of molecular weight is less than the errors associ-
usually reported in terms of specific gravity (SG) or relative ated with predictive methods for this very useful parameter.
density, defined as Because petroleum fractions are mixtures of hydrocar-
bon compounds, mixture molecular weight is defined as
density of liquid at temperature T
SG = (4.1) an average value called the “number average molecular
denssity of water at temperature T weight” or simply “molecular weight of the mixture,” and it
Because the standard conditions adopted by the petro- is calculated as M = ∑ xi Mi , where xi and Mi are the mole
leum industry are 60 °F (15.5 °C) and 1 atm, normally SG i

values of liquid hydrocarbons are reported at these con- fraction and molecular weight of component i, respectively.
ditions. At a reference temperature of 60 °F (15.5 °C), the Molecular weight of the mixture, M, represents the ratio
density of liquid water is 0.999 g/cm3 (999 kg/m3) or 8.337 of the total mass of the mixture to the total moles in the
lb/gal (U.S.). Therefore, for a hydrocarbon or a petroleum mixture. Exact knowledge of molecular weight of a mixture
fraction, the SG is defined as requires the exact composition of all compounds in the
mixture. For petroleum fractions such exact knowledge
density of liquid at 60 °F in g / cm3 is not available because of the many components present
SG (60 °F / 60 °F) = (4.2)
0.999 g / cm3 in the mixture. Therefore, experimental measurement of
The density of water at 60 °F is 0.999, or approximately mixture molecular weight is needed in lieu of the exact
1 g/cm3; therefore, values of SG are nearly the same as the composition of all compounds in the mixture.
density of liquid at 15.5 °C (289 K) in g/cm3. SG defined by There are three methods that are widely used to mea-
the above equation is slightly different from the SG defined sure the molecular weight of various petroleum fractions.
in the SI system as the ratio of the density of hydrocarbon These are cryoscopy, the vapor pressure method, and the
at 15 °C to that of water at 4 °C, designated by d15 . Note that size exclusion chromatography (SEC) method. For heavy
4
density of water at 4 °C is exactly 1 g/cm3 and therefore d15 is petroleum fractions and asphaltenic compounds the SEC
equal to the density of liquid hydrocarbon at 15 °C in g/cm3.
4
method is commonly used to measure the molecular weight
The relation between these two SGs is approximately given distribution in the fraction. The SEC method is mainly used
as SG = 1.001 d415 to determine molecular weights of polymers in the range of
In the early years of the petroleum industry, the Ameri- 2000 to 2 × 106. This method is also called “gel permeation
can Petroleum Institute (API) defined the API gravity (°API ) chromatography” (GPC) and is described in the ASTM
to quantify the quality of petroleum products and crude oils. D5296 test method. In the GPC method, by comparing the
The API gravity is defined as [5] elution time of a sample with that of a reference solution,
the molecular weight of the sample can be determined. The
SEC experiment is usually performed for heavy residues
141.5 and asphaltenes in crude oils and gives the weight percent
API Gravity =
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- – 131.5 (4.3)
SG (at 60 °F) of various constituents versus molecular weight
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Chapter 4 n Properties, Specifications, and Quality of Crude Oil 81

The vapor pressure method is based on the measure- present in the mixture are known. Because of the diversity
ment of the difference between vapor pressure of the sample and number of constituents of a petroleum mixture, the
and that of a known reference solvent with a vapor pressure determination of such exact composition is nearly impos-
greater than that of the sample. This method is described by sible. Hydrocarbons can generally be identified by their
the ASTM D2503 test method and is applicable to oils with carbon number or by their molecular type. Carbon num-
an IBP of greater than 220 °C. The third and most widely used ber distribution may be determined from fractionation by
method of determining the molecular weight of an unknown distillation or by molecular weight. However, for narrow-
petroleum mixture is by the cryoscopy method, which is boiling-range petroleum products and petroleum cuts in
based on freezing point depression. Further details of experi- which the carbon number range is quite limited, knowledge
mental methods to measure molecular weight of various of the molecular type of compounds is very important. After
petroleum products are given in ASTM Manual 50 [2]. distillation data, molecular type composition is the most
important characteristic of petroleum fractions. On the
basis of the nature of petroleum mixture, there are several
4.4 Refractive Index ways to express the composition of a petroleum mixture.
Refractive index, or the refractivity for a substance, is Some of the most important types of composition are
defined as the ratio of velocity of light in a vacuum to the • PONA (paraffins, olefins, naphthenes, and aromatics)
velocity of light in the substance (fluid) and is a dimen- • PNA (paraffins, naphthenes, and aromatics)
sionless quantity shown by n. In other words, when a light • PIONA (paraffins, isoparaffins, olefins, naphthenes,
beam passes from one substance (air) to another (a liquid), and aromatics)
it is bent or refracted because of the velocity difference, • SARA (saturates, aromatics, resins, and asphaltenes)
and the refractive index indicates the degree of this refrac- • Elemental analysis (C, H, S, N, O)
tion. Because the velocity of light in a fluid is less than the Because most petroleum fractions are free of olefins,
velocity of light in a vacuum, the refractive index of a fluid the hydrocarbon types can be expressed in terms of only
is greater than unity. Liquids have higher refractive index PINA, and if paraffins and isoparaffins are combined into a
values than do gases. For gases, the values of refractive single fraction, they are simply expressed in terms of PNA
index are very close to unity. Usually the refractive index of composition. This type of analysis is useful for light and
hydrocarbons is measured by the sodium D-line at 20 °C and narrow-boiling-range petroleum products such as distil-
1 atm. The refractive index is a very useful characterization lates from atmospheric crude distillation units. The SARA
parameter for pure hydrocarbon and petroleum fractions, analysis is useful for heavy petroleum fractions, residues,
especially in relation to molecular-type composition. and fossil fuels (i.e., coal liquids) that have high contents
Refractive indices of hydrocarbons vary from 1.35 of aromatics, resins, and asphaltenes. Elemental analysis
to 1.60; however, aromatics have refractive index values gives information on hydrogen and sulfur contents as well
greater than naphthenes., which in turn have refractive as the carbon-to-hydrogen ratio, which is indicative of the
indices greater than paraffins. Paraffinic oils have lower quality of petroleum products.
refractive index values. For mixtures, refractive index is a Generally three techniques may be used to analyze
bulk property that can be easily and accurately measured by petroleum fractions:
an instrument called a refractometer. Refractive index can 1. Separation by solvents
be measured by digital refractometers with a precision of 2. Chromatography methods
±0.0001 and temperature precision of ±0.1 °C. The amount 3. Spectroscopic methods
of sample required to measure refractive index is very small, Method of separation by solvent is particularly use-
and ASTM D1218 provides a test method for clear hydrocar- ful for heavy petroleum fractions and residues contain-
bons with values of refractive indices in the range of 1.33– ing asphaltenes, resins, and saturate hydrocarbons. For
1.5 and the temperature range of 20–30 °C. In the ASTM example, if n-heptane is added to a heavy oil, asphaltenes
D1218 test method, the Bausch and Lomb refractometer is precipitate whereas the other constituents form a solu-
used. Refractive index of viscous oils, with values up to 1.6, tion. If the solvent is changed to propane, because of the
can be measured by the ASTM D1747 test method. Samples greater difference between the structure of the solvent and
must have clear color to measure their refractive index; the high-molecular-weight asphaltenes, more asphaltenic
however, for darker and more viscous samples in which compounds precipitate. Similarly, if acetone is added to
the actual refractive index value is outside of the range of a deasphalted oil (DAO), resins precipitate whereas low-
measurement by a refractometer, a light solvent can dilute molecular-weight hydrocarbons remain soluble in acetone.
samples to measure the refractive index of the solution. One of the disadvantages of all of the solvent separa-
From the composition of the solution and refractive indices tion techniques is that in some instances a very low tem-
of the pure solvent and that of the solution, the refractive perature (0–10 °C) is required, which causes inconvenience
index of viscous samples can be determined. Because of in a laboratory operation. Another difficulty is that in many
the simplicity and importance of the refractive index, it cases large volumes of solvent may be required and that the
would be very useful for laboratories to measure and report solvent must have a sufficiently low boiling point to allow
its value at 20 °C for a petroleum product, especially if the its complete removal from the product. ASTM [1] provides
composition of the mixture is not reported. several methods based on solvent separation to determine
amounts of asphaltenes. For example, in the ASTM D4124
4.5 Compositional Analysis method asphaltene is separated by n-heptane. Asphaltenes
Petroleum fractions are mixtures of many different types are soluble in liquids with a surface tension greater than
of hydrocarbon compounds. A petroleum mixture is well 25 dyne/cm, such as pyridine, carbon disulfide, carbon
defined if the composition and structure of all compounds
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
tetrachloride, and benzene [6].
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82 Petroleum Refining and Natural Gas Processing

Chromatography methods are commonly used in the c omposition of organic and inorganic compounds. How-
petroleum industry to identify compounds or to deter- ever, use of MS is limited to organic compounds that are
mine boiling distribution. If the mobile phase in the stable up to 300 °C (570 °F). At higher temperatures, ther-
chromatography column is gas, the instrument is a gas mal decomposition may occur and the analysis will be
chromatograph, whereas for liquid mobile phase it is a biased [6]. Through MS analysis, hydrocarbons of similar
liquid chromatograph. Components can be separated by boiling points can be identified. In the MS analysis, molecu-
their boiling points through GC analysis. In advanced lar weight and chemical formula of hydrocarbons and their
petroleum refineries, automatic online GCs are used for amounts can be determined. The most powerful instrument
continuous analysis of various streams to control the qual- to analyze petroleum distillates is combination of a GC and
ity of products. A stream may be analyzed every 20 min an MS, called a GC-MS instrument, which separates com-
and automatic adjustment can be made to the refinery pounds through boiling point and molecular weight. For
unit. In crude assay analysis, distillation is being replaced heavy petroleum fractions containing high-boiling-point
by chromatography techniques. The liquid chromatography compounds, an integrated LC-MS unit may be suitable for
(LC) method is used for less volatile mixtures such as heavy analysis of mixtures; however, use of LC-MS is more dif-
petroleum fractions and residues. Use of LC in separation ficult than GC-MS because in LC-MS the solvent must be
of saturated and aromatic hydrocarbons is described in removed from the elute before it can be analyzed by MS.
the ASTM D2549 test method. Various forms of chroma- Another type of separation is by SEC or GPC, which
tography techniques have been applied to a wide range of can be used to determine molecular weight distribution of
petroleum products for analysis such as PONA, PIONA, heavy petroleum fractions. Fractions are separated accord-
PNA, and SARA. One of the most useful types of LC is high- ing to their size and molecular weight, and the method is
performance liquid chromatography (HPLC), which can be particularly useful to determine the amount of asphaltenes.
used to identify different types of hydrocarbon groups. One Asphaltenes are polar multiring aromatic compounds with
particular application of HPLC is to identify asphaltene molecular weights greater than 1000, and it is assumed that
and resin-type constituents in nonvolatile feedstocks such in this molecular weight range only aromatics are present
as residua. The total time required to analyze a sample by in a petroleum fraction.
HPLC is just a few minutes. One of the main advantages of
HPLC is that the boiling range of the sample is immaterial. 4.5.1 Elemental Analysis
The accuracy of chromatography techniques mainly The main elements present in a petroleum fraction are carbon
depends on the type of detector used [6]. Flame ionization (C), hydrogen (H), nitrogen (N), oxygen (O), and sulfur (S).
detectors (FID) and thermal conductivity detectors (TCD) The most valuable information from elemental analysis
are widely used in GC. For LC, the most common detectors that can be obtained is the C/H ratio and sulfur content of
are refractive index detectors (RID) and wavelength ultra- a petroleum mixture, from which one can determine the
violet (UV) detectors. UV spectroscopy is particularly useful quality of oil. As boiling points of fractions increase or their
to identify the types of aromatics in asphaltenic fractions. API gravity decrease, the C/H ratio, sulfur content, nitrogen
Another spectroscopy method is conventional infrared (IR) content, and the amount of metallic constituents increase,
spectroscopy, which yields information about the functional signifying a reduction in the quality of an oil. Sulfur content
features of various petroleum constituents. For example, IR of very heavy fractions can reach 6–8 % and the nitrogen
spectroscopy aids in the identification of N-H and O-H func- content can reach 2.0-2.5 wt. %. There are specific methods
tions, in the nature of polymethylene chains (C-H), and in the to measure these elements individually. However, instru-
nature of any polyaromatic hydrocarbon (PAH) systems [6]. ments do exist that measure these elements all together, and
Another analysis used to identify molecular groups in these are called elemental analyzers. ASTM test methods
petroleum fractions is mass spectrometry (MS). In general, for elemental analysis of petroleum products and crude oils
there is a difference between spectroscopy and spectrom- include hydrogen content (ASTM D1018, D3178, D3343),
etry methods although in some references this difference nitrogen content (ASTM D3179, D3228, D3431), and sulfur
is not acknowledged. Spectroscopy refers to the techniques content (ASTM D129/IP 61, D1266/IP 107, D1552, D4045).
where the molecules are excited by various sources such as Usually carbon dioxide, water, and sulfur dioxide are
UV and IR and they return to their normal state. Spectrom- detected by infrared detectors (IRDs) whereas N2 is deter-
etry refers to the techniques where the molecules are actu- mined by the TCD method.
ally ionized and fragmented. Evolution of spectroscopic Another group of heteroatoms found in petroleum mix-
methods comes after chromatography techniques, nonethe- tures are metallic constituents. The amounts of these met-
less, and in recent decades they have received considerable als are in the range of few hundreds to thousand parts per
attention. While volatile and light petroleum products can million and their amounts increase with increase in boiling
be analyzed by GC, heavier and nonvolatile compounds can points or decrease in the API gravity of oil. Even a small
be analyzed and identified by spectrometric methods. One amount of these metals (particularly nickel, vanadium, iron
of the most important types of spectrometry techniques and copper) in the feedstocks for catalytic cracking have
in analysis of petroleum fractions is MS. In this method, negative effects on the activity of catalysts and result in
masses of molecular and atomic components, which are increased coke formation. Metallic constituents are associ-
ionized in the gaseous state by collision with electrons, are ated with heavy compounds and mainly appear in residuas.
measured. The advantage of MS over other spectrometric There is no general method to determine the composition of
methods is its high reproducibility of quantitative analy- all metals at once, but ASTM [1] provides test methods for
sis and information on molecular type in complex mix- determination of various metallic constituents (i.e., ASTM
tures. MS can provide the most detailed quantitative and D1026, D1262, D1318, D1368, D1548). Another method is
qualitative information about the atomic and molecular to burn the oil sample in which metallic compounds appear
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Chapter 4 n Properties, Specifications, and Quality of Crude Oil 83

in inorganic ashes. The ash should be digested by an acid liquid petroleum products. Because RVP does not represent
and the solution is examined for metal species by atomic TVP, the current tendency is to substitute RVP with more
absorption spectroscopy [6]. modern and meaningful techniques. The more sophisticated
instruments for measurement of TVP at various temperatures
4.6 Vapor Pressure, Vapor-to-Liquid are discussed in the ASTM D4953 test method. This method
Ratio, and Volatility Index can be used to measure the RVP of gasolines with oxygenates,
In a closed container, the vapor pressure of a pure com- and measured values are closer to actual vapor pressures [1].
pound is the force exerted per unit area of walls by the Once RVP is known, it can be used to determine two
vaporized portion of the liquid. Vapor pressure can also be other volatility characteristics—the vapor-to-liquid (V/L) ratio
defined as a pressure at which vapor and liquid phases of and fuel volatility index (FVI), which are specific characteris-
a pure substance are in equilibrium with each other. The tics of spark-ignition engine fuels such as gasolines. V/L ratio
vapor pressure is also called “saturation pressure” and the is a volatility criterion that is mainly used in the United State
corresponding temperature is called “saturation tempera- and Japan whereas FVI is used in France and Europe [8].
ture.” In an open air under atmospheric pressure, a liquid The V/L ratio at a given temperature represents the volume
at any temperature below its boiling point has its own of vapor formed per unit volume of liquid initially at 0 °C.
vapor pressure that is less than 1 atm. When vapor pres- The procedure of measuring the V/L ratio is standardized
sure reaches 1 atm, the saturation temperature becomes as ASTM D2533. The volatility of a fuel is expressed as the
the normal boiling point. Vapor pressure increases with temperature levels at which the V/L ratio is equal to certain
temperature and the highest value of vapor pressure for a values. A simple relation to calculate T(V/L)20 is given in terms
substance is its critical pressure, in which the correspond- of RVP and distillation temperatures at 10 and 50 % [2]:
ing temperature is the critical temperature.
Vapor pressure is a very important thermodynamic prop- T(V/L)20 = 0.2T10 + 0.17T50 – 33RVP (4.5)
erty of any substance and it is a measure of the volatility of
a fluid. Compounds with a higher tendency to vaporize have where T10 and T50 are temperatures at 10 and 50 volume
higher vapor pressures. At a fixed temperature, vapor pres- 5 distilled on the ASTM D86 distillation curve. All tem-
sure decreases with increase in molecular weight or carbon peratures are in degrees Celsius and RVP is in bar. Several
number. Vapor pressure is a useful parameter in calculations petroleum refining companies in the United States such
related to hydrocarbon losses and flammability of hydrocar- as Exxon and Mobil use the critical vapor locking index
bon vapor in the air. More volatile compounds are more ignit- (CVLI), which is also related to the volatility index [2].
able than heavier compounds. For example n-butane is added FVI is a characteristic of a fuel for its performance dur-
to gasoline to improve its ignition characteristics. Low vapor ing hot operation of the engine. In France, specifications
pressure compounds reduce evaporation losses and chance require that its value be limited to 900 in summer, 1000
of vapor lock. Therefore, for a fuel there should be a compro- in fall/spring, and 1150 in the winter season. Automobile
mise between low and high vapor pressure. Vapor pressure is manufacturers in France require their own specifications
also needed in the calculation of equilibrium ratios for phase that the value of FVI not to exceed 850 in summer [8].
equilibrium calculations. Methods of calculation of vapor
pressure are given in detail in ASTM Manual 50 [2]. 4.7 Flash Point
For crude oils, petroleum fractions, and hydrocarbon Flash point for a hydrocarbon or a fuel is the minimum
mixtures, the method of Reid is used to measure vapor temperature at which vapor pressure of the hydrocarbon
pressure at 100 °F. Reid vapor pressure (RVP) is the absolute is sufficient to produce the vapor needed for spontaneous
pressure exerted by a mixture at 37.8 °C (311 K or 100 °F) ignition of the hydrocarbon with the air with the presence
at a vapor-to-liquid volume ratio of 4. The RVP is one of of an external source (i.e., spark or flame). From this defini-
the important properties of gasolines and jet fuels and it tion, it is clear that hydrocarbons with higher vapor pres-
is used as a criterion for blending of products. RVP is also sures (lighter compounds) have lower flash points. Flash
a useful parameter for estimation of losses from storage point generally increases with an increase in boiling point.
tanks during filling or draining. For example, according to Flash point is an important parameter for safety consider-
the Nelson method, losses can be approximately calculated ations, especially during storage and transportation of vola-
as losses (vol %) = (14.5RVP – 1)/6, where RVP is in bar [2]. tile petroleum products (i.e., liquefied petroleum gas, light
The apparatus and procedures for standard measurement naphtha, gasoline) in a high temperature environment. The
of RVP are specified in ASTM D323 or the Institute of Petro- surrounding temperature around a storage tank should
leum (IP) 402 test methods. In general, true vapor pressure always be less than the flash point of the fuel to avoid the
(TVP) is higher than RVP because of light gases dissolved possibility of ignition. Flash point is used as an indication
in liquid fuel; however, RVP is approximately equivalent to of the fire and explosion potential of a petroleum product.
vapor pressure at 100 °F (38 °C). Flash point is related to the volatility of a fuel and the
The RVP and boiling range of gasoline governs ease of presence of light and volatile components, with higher vapor
starting, engine warm-up, mileage economy, and tendency pressure corresponding to lower flash points. Generally for
toward vapor lock [7]. Vapor lock tendency is directly related crude oils with RVP greater than 0.2 bar, the flash point is
to RVP, and at ambient temperature of 21 °C (70 °F), the less than 20 °C [8]. Flash point is an important character-
maximum allowable RVP is 75.8 kPa (11 psia), whereas this istics of light petroleum fractions and products under high
limit at 32 °C (90 °F) reduces to 55.2 kPa (8 psia). RVP can temperature environment and is directly related to the safe
also be used to estimate TVP of petroleum fractions at vari- storage and handling of such petroleum products. There are
ous temperatures as shown in reference 2. TVP is important several methods of determining flash points of petroleum
in the calculations related to losses and rate of evaporation of
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fractions. The Closed Tag method (ASTM D56) is used for
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84 Petroleum Refining and Natural Gas Processing

petroleum stocks with flash points below 80 °C (175 °F). of the freezing point is important and it is one of the major
The Pensky–Martens method (ASTM D93 or ISO 2719) is specifications of jet fuels and kerosenes. For a pure com-
used for all petroleum products except waxes, solvents, and pound, the freezing point is the temperature at which liquid
asphalts. The Cleveland Open Cup method (ASTM D92 or solidifies at a pressure of 1 atm. Similarly, the melting point
ISO 2592) is used for petroleum fractions with flash points is the temperature that a solid substance liquefies at 1 atm.
above 80 °C (175 °F), excluding fuel oil. This method usually A pure substance has the same freezing and melting points;
gives flash points 3–6 °C higher than the above two meth- however, for petroleum mixtures, there are ranges of melt-
ods [9]. Flash point should not be mistaken with fire point, ing and freezing points versus percent of the mixture melted
which is defined as the minimum temperature at which the or frozen. For a mixture the initial melting point is close to
hydrocarbon will continue to burn for at least 5 s after being the melting point of the lightest compound in the mixture
ignited by a flame. There are several correlations to estimate whereas the initial freezing point is close to the freezing point
flash point of hydrocarbons and petroleum fractions that are (or melting point) of the heaviest compound in the mixture.
discussed in ASTM Manual 50 [2]. Because the melting point increases with molecular weight,
for petroleum mixtures the initial freezing point is greater
4.8 Viscosity and Kinematic Viscosity than the initial melting point. Melting point is an important
Viscosity, commonly shown by μ, is a molecular property characteristic parameter for petroleum and paraffinic waxes.
of a fluid and is defined from Newton’s law of viscosity. Freezing point is one of the important characteristics of
Viscosity is a property that is related to fluidity of a liquid, aviation fuels, in which it is determined by the procedures
and a liquid with higher viscosity has less tendency to flow described in the ASTM D2386 (United States), IP 16 (United
whereas low-viscosity fluids can easily flow. Viscosity is Kingdom), and NF M 07-048 (France) test methods. The
needed in calculations related to the power requirement maximum freezing point of jet fuels is an international speci-
to transport a fluid and is a function of temperature. Vis- fication that is required to be at –47 °C (–53 °F) as specified in
cosity of gases is less than those of liquids. Viscosity of the “Aviation Fuel Quantity Requirements for Jointly Oper-
liquids decreases with increase in temperature while for ated Systems” [8]. This maximum freezing point indicates
gases viscosity increases with temperature. Viscosity is the lowest temperature that the fuel can be used without risk
also an important characteristic of lubricating engine oils. of separation of solidified hydrocarbons (wax). Such separa-
Viscosity of liquids usually is measured in terms of kine- tion can result in the blockage in fuel tank, pipelines, noz-
matic viscosity, which is defined as the ratio of absolute zles, and filters [9]. Methods of calculation of freezing points
(dynamic) viscosity to absolute density (ν = μ/ρ). Kinematic of petroleum fractions are discussed in ASTM Manual 50 [2].
viscosity is expressed in centistokes (cSt), Saybolt Universal
seconds (SUS), and Saybolt Furol seconds (SFS). Values of 4.10 Pour Point
kinematic viscosity for pure liquid hydrocarbons are usu- The pour point of a petroleum fraction is the lowest tem-
ally measured and reported at two reference temperatures perature at which the oil will pour or flow when it is cooled
of 38 °C (100 °F) and 99 °C (210 °F) in cSt. However, other without stirring under standard cooling conditions. Pour
reference temperatures of 40 °C (104 °F), 50 °C (122 °F), and point represents the lowest temperature at which an oil can
60 °C (140 °F) are also used to report kinematic viscosities be stored and still be capable of flowing under gravity and
of petroleum fractions. Viscosity is one of the most impor- is one of the low-temperature characteristics of heavy frac-
tant properties of lubricating oils and heavy oils. tions. When the temperature is less than the pour point of a
When viscosity at two temperatures is known, one can petroleum product it cannot be stored or transferred through
obtain the viscosity at other temperatures. Measurement of a pipeline. Test procedures for measuring pour points of
viscosity is easy, but the method and the instrument depend petroleum fractions are given under the ASTM D97 (ISO 3016
on the type of sample. For Newtonian and high-shear fluids or IP 15) and ASTM D5985 methods. For commercial for-
such as engine oils, viscosity can be measured by a capillary mulation of engine oils, the pour point can be lowered to the
U-type viscometer. An example of such a viscometer is the limit of –25 and –40 °C. This is achieved by using pour point
Cannon–Fenske viscometer. The test method is described in depressant additives, which inhibit the growth of wax crystals
ASTM D445, which is equivalent to the ISO 3104 method, in the oil [10]. The presence of wax and heavy compounds
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

and kinematic viscosity is measured at temperatures from causes an increase in the pour point of petroleum fractions.
15 to 100 °C (~60–210 °F). In this method, repeatability and
reproducibility are 0.35 and 0.7 %, respectively [2]. Another 4.11 Cloud Point
type of viscometer is a rotary viscometer, which is used for The cloud point is the lowest temperature at which wax
a wide range of shear rates, especially for low shear rate crystals begin to form by a gradual cooling under standard
and viscous fluids such as lubricants and heavy petroleum conditions. At this temperature, the oil becomes cloudy and
fractions. In these viscometers, fluid is placed between two the first particles of wax crystals are observed. The standard
surfaces—one is fixed, and the other one is rotating. In these procedure to measure the cloud point is described under
viscometers absolute viscosity can be measured, and an the ASTM D2500, IP 219, and ISO 3015 test methods. Cloud
example of such a viscometer is the Brookfield viscometer. point is another cold characteristic of petroleum oils under
low-temperature conditions and increases as the molecular
4.9 Freezing and Melting Points weight of an oil increases. Cloud points are measured for oils
Petroleum and most petroleum products are in the form of a that contain paraffins in the form of wax; therefore, for light
liquid or gas at ambient temperatures. However, for oils con- fractions such as naphtha or gasoline, no cloud point data
taining heavy compounds such as waxes or asphaltenic oils, are reported. Cloud points usually occur at 4–5 °C (7–9 °F)
problems may arise from solidification, which causes the oil above the pour point, although the temperature differential
to lose its fluidity characteristics. For this reason, knowledge could be in the range of 0–10 °C (0–18 °F). The difference
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Chapter 4 n Properties, Specifications, and Quality of Crude Oil 85

between cloud and pour point depends on the nature of oil, at atmospheric pressure is 100 Pvap, where Pvap is the vapor
and there is no simplified method to predict this difference. pressure in atmosphere. When the calculated volume per-
Cloud point is one of important characteristics of crude oils cent of a hydrocarbon in the air is within the flammability
under low-temperature conditions. As temperature decreases range, then the mixture is flammable by a spark or flame.
below the cloud point, the formation of wax crystals is accel- The flammability ranges for some pure hydrocarbons are as
erated. Therefore, low cloud point products are desirable follows: propane, 2.1–9.5; butane, 1.8–8.4; benzene, 1.4–7.1;
under low-temperature conditions. Wax crystals can plug hydrogen, 4.3–45.5; and methanol, 2.3–36.0 vol % [2].
the fuel system lines and filters, which could lead to stalling
aircraft and diesel engines under cold conditions. Because 4.13 Octane Number
cloud point is higher than pour point, it can be considered Octane number is a parameter defined to characterize
that the knowledge of cloud point is more important than the antiknock characteristic of a fuel (gasoline) for spark-
the pour point in establishing distillate fuel oil specifications ignition engines. Octane number is a measure of a fuel’s
for cold-weather usage [10]. Table 4.1 shows the difference ability to resist autoignition during compression and before
between cloud and pour points for some petroleum prod- ignition by a spark. Higher octane number fuels have better
ucts. The amount of n-paraffins in petroleum oil has a direct engine performance. The octane number of a fuel is mea-
effect on the cloud point of a fraction. The presence of gases sured based on two reference hydrocarbons of n-heptane,
dissolved in oil reduces the cloud point, which is desirable. with an assigned octane number of zero, and a specific iso-
The exact calculation of cloud point requires solid-liquid octane (2,2,4-trimethylpentane), with an assigned octane
equilibrium calculations, which are discussed in reference 2. number of 100. A mixture of 70 vol % 2,2,4-trimethylpen-
tane and 30 vol % n-heptane has an octane number of 70.
4.12 Flammability Range There are two methods of measuring the octane number
Three elements are required for combustion: fuel (hydro- of a fuel in the laboratory: motor octane number (MON)
carbon vapor), oxygen (i.e., air), and a spark to initiate the and research octane number (RON). MON is indicative of
combustion. One important parameter for good combus- high-speed performance (900 rpm) and is measured under
tion is the ratio of air to hydrocarbon fuel. The combustion heavy road conditions (ASTM D357). RON is indicative of
does not occur if there is too much air (little fuel) or too normal road performance under low engine speed (600 rpm)
little air (too much fuel). This suggests that combustion city driving conditions (ASTM D908). A third type of octane
occurs when the hydrocarbon concentration in the air is number is defined as the posted octane number (PON),
within a certain range. This range is called the flammability which is the arithmetic average of MON and RON [PON =
range and usually is expressed in terms of lower and upper (MON + RON)/2]. Isoparaffins generally have a higher octane
volume percent in the mixture of hydrocarbon vapor and number than normal paraffins. Naphthenes have a relatively
air. The actual volume percent of hydrocarbon vapor in higher octane number than their corresponding paraffins,
the air may be calculated from the vapor pressure of the and aromatics have very high octane numbers. The octane
hydrocarbon. When a liquid is open to the atmosphere at a number of a fuel can be improved by adding tetraethyl
temperature of T, in which the vapor pressure of liquid is lead (TEL) or methyl tertiary butyl ether (MTBE). Use of
Pvap, the volume percent of the compound vapor in the air lead (Pb) to improve the octane number of fuels is limited

Table 4.1—Cloud (TCL) and Pour (TP) Points and Their Differences for
Some Petroleum Products
Fraction API Gravity TP ( °C) TCL ( °C) TP–TCL ( °C)
Indonesian distillate 33.0 –43.3 –53.9 10.6
Australian GO 24.7 –26.0 –30.0 4.0
Australian HGO 22.0 –8.0 –9.0 1.0
Abu Dhabi LGO 37.6 –19.0 –27.0 8.0
Abu Dhabi HGO 30.3 7.0 2.0 5.0
Abu Dhabi distillate 21.4 28.0 26.0 2.0
Abu Dhabi diesel 37.4 –12.0 –12.0 0.0
Kuwaiti kerosene 44.5 –45.0 –45.0 0.0
Iranian kerosene 44.3 –46.7 –46.7 0.0
Iranian kerosene 42.5 –40.6 –48.3 7.8
Iranian GO 33.0 –11.7 –14.4 2.8
North Sea GO 35.0 6.0 6.0 0.0
Nigerian GO 27.7 –32.0 –33.0 1.0
Middle East kerosene 47.2 –63.3 –65.0 1.7
Middle East kerosene 45.3 –54.4 –56.7 2.2
Middle East kerosene 39.7 –31.1 –34.4 3.3
Middle East distillate 38.9 –17.8 –20.6 2.8
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86 Petroleum Refining and Natural Gas Processing

molecule in which one atom of hydrogen is replaced by

an amino (–NH2) group (C6H5—NH2). The aniline point is
DURPDWLFV
important in the characterization of petroleum fractions and
5(6($5&+2&7$1(180%(5

analysis of molecular type. The aniline point is also used as

a characterization parameter for the ignition quality of diesel
fuels. It is measured by the ASTM D611 test method. Within
a hydrocarbon group, aniline point decreases with molecular

weight or carbon number (i.e., 536.9 ºC for methane to 201.9
for n-C20), but for the same carbon number it increases from
QSDUDIILQV
QDSKWKHQHV aromatics to paraffinic hydrocarbons. Generally, oils with
lower aniline points have higher aromatic content.

QDONDQH 4.15 Cetane Number and Diesel Index
LVRSDUDIILQV
ROHILQV For diesel engines, the fuel must have a characteristic that
QDON\OF\FORSHQWDQHV favors autoignition. The ignition delay period can be evalu-
QDON\OEHQ]HQHV
ated by the fuel characterization factor called cetane number
(CN). The behavior of a diesel fuel is measured by compar-
%2,/,1*32,17& ing its performance with two pure hydrocarbons: n-cetane
or n-hexadecane (n-C16H34), which are given the CN of 100,
Figure 4.2—RON of different families of hydrocarbons. and a-methylnaphthalene, which is given the CN of 0. A die-
sel fuel has a CN of 60 if it behaves like a binary mixture of 60
in many industrial countries. In these countries MTBE is vol % cetane and 40 vol % a-methylnaphthalene. In practice,
used for octane number improvement; MTBE has MON and heptamethylnonane (HMN), a branched isomer of n-cetane
RON values of 99 and 115, respectively [2]. Lead generally with a CN of 15, is used instead of a-methylnaphthalene [8].
improves octane number of fuels better than MTBE. The Therefore, in practice, the CN is defined as
addition of 0.15 g Pb/L to a fuel with a RON of approximately
92 can improve its octane number by 2–3 points. With 0.6 CN = vol % (n-cetane) + 0.15(vol % HMN) (4.6)
g Pb/L one may improve the octane number by 10 points.
However, as mentioned above, because of environmental The CN of a diesel fuel can be measured by the ASTM D613
hazards, use of lead is restricted in many North American test method. The shorter the ignition delay period, the higher
and Western European countries, and unleaded fuels are the CN value. Higher CN fuels reduce combustion noise
used all over the world. Values of the octane number mea- and permit improved control of combustion, resulting in
sured without any additives are called “clear octane num- increased engine efficiency and power output. Higher CN
ber.” However, recently it was found that use of MTBE could fuels tend to result in easier starting and faster warm-up in
cause pollution of groundwater, and as a result dimethyl cold weather. CN requirements of fuels vary with their uses.
carbonate is being considered as an alternative additive to For high-speed city buses in which kerosene is used as fuel
improve octane number. For pure hydrocarbons, aromatics the required CN is 50. For premium diesel fuel for use in high-
have the higher octane number, whereas n-paraffins have speed buses and light marine engines, the required number
the lowest octane number values when compared with other is 47, whereas for marine distillate diesel for low-speed buses
groups, as shown in Figure 4.2. Values of RON and MON of and heavy marine engines the required CN is lower. In France
some oxygenates that may be used as additives to improve the minimum required CN of fuels by automotive manufac-
the octane number of fuels are given in Table 4.2 [2]. turers is 50. The products distributed in France and Europe
have CNs in the range of 48–55. Higher CN fuels and better
4.14 Aniline Point starting conditions can reduce air pollution [8].
The aniline point for a hydrocarbon or petroleum fraction Because determination of CN is difficult and costly,
is defined as the minimum temperature at which equal vol- ASTM D976 (IP 218) proposes a method of calculation. The
umes of liquid hydrocarbon and aniline are miscible. Aniline calculated number is called the “calculated cetane index”
is an aromatic compound with a structure of a benzene (CCI) and can be determined from SG and distillation
data [2]. Another characteristic of diesel fuels is called the
“diesel index” (DI), which is defined in terms of API gravity
Table 4.2—Octane Numbers of Some and aniline point.
Alcohols and Ethers (Oxygenates) The CN of diesel fuels can be improved by adding com-
Compound RON MON pounds such as 2-ethyl-hexyl nitrate or other types of alkyl
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nitrates. CN is usually improved by 3–5 points when 300–

Methanol 125–135 100–105
1000 ppmw of such compounds is added. Generally, CCI is
MTBE 113–117 95–101 less than the measured CN, and for this reason in France
Ethanol 120–130 98–103 automobile manufacturers have established minimum CN
ETBE 118–122 100–102 for the CCI (49) and the measured CN (50) for the quality
requirement of the fuels [8].
TBA 105–110 95–100
TAME 110–114 96–100 4.16 Carbon Residue
ETBE, ethyl-tertiary-butyl ether; TBA, tert-butyl alcohol; TAME, tertiary- When a petroleum fraction is vaporized in the absence of
amyl-methyl ether. air at atmospheric pressure, the nonvolatile compounds
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Chapter 4 n Properties, Specifications, and Quality of Crude Oil 87

have a carbonaceous residue known as carbon residue (CR). factor, denoted by KW, is one of the oldest characterization
Therefore, heavier fractions with more aromatic contents factors originally defined by Watson et al. of Universal
have higher CRs, whereas volatile and light fractions such Oil Products (UOP) in the mid-1930s. For this reason, the
as naphthas and gasolines have no CRs. CR is a particu- parameter is sometimes called the UOP characterization
larly important characteristic of crude oils and petroleum factor and is defined as
residues. Higher CR values indicate low-quality fuel and
(1.8Tb )
1/ 3
less hydrogen content. There are two older different test (4.7)
methods to measure CRs: Ramsbottom (ASTM D524) and KW =
SG
Conradson (ASTM D189). The relationship between these
methods is also given by the ASTM D189 method. Oils that
where:
have ash-forming compounds give erroneously high CRs by
Tb = mean average normal boiling point in K
both methods. For such oils, ash should be removed before
SG = specific gravity at 15.5 °C.
the measurement. There is a more recent test method
The purpose of definition of this factor was to classify
(ASTM D4530) that requires smaller sample amounts and
the type of hydrocarbons in petroleum mixtures. The naph-
is often referred to as microcarbon residue (MCR), and, as a
thenic hydrocarbons have KW values between paraffinic and
result, it is a less precise but it is a practical technique [6].
aromatic compounds. In general, aromatics have low KW
In most cases CRs are reported in weight percent by the
values whereas paraffins have high values. Further infor-
Conradson method, which is designated by % CCR.
mation on limitations and uses of this parameter is given in
CR can be correlated to several other properties. It
ASTM Manual 50 [2]. Because for very heavy fractions the
increases with an increase in carbon-to-hydrogen ratio
normal boiling point cannot be measured, this parameter is
(CH); sulfur, nitrogen, and asphaltene content; or viscos-
not useful for heavy oils.
ity of the oil. The most precise relation is between CR and
the hydrogen content: as hydrogen content increases, the
CR decreases [6]. CR is nearly a direct function of high- 4.18.2 Refractivity Intercept
boiling-point asphaltic materials, and Nelson has reported A plot of refractive index of n-paraffins versus density (d20)
a linear relation between CR and asphalt yield. One of the in the carbon number range of C5–C45 is a straight line
main characteristics of residuum is its asphaltene con- represented by the equation n = 1.0335 + 0.516d20, with
tent. Asphaltenes are insoluble in low-molecular-weight an R2 value of 0.9998 (R2 = 1 for an exact linear relation).
n-alkanes, including n-pentane. Knowledge of n-pentane Other hydrocarbon groups show similar performance with
insolubles in residual oils is quite important in determin- an exact linear relation between n and d. On the basis of
ing yields and product quality for deasphalting, thermal this observation, a characterization parameter called the
visbreaking, and hydrodesulfurization processing. d
refractivity intercept, Ri, was defined as Ri = n − , where n
2
4.17 Smoke Point and d are the refractive index and density of the liquid
Smoke point is a characteristic of aviation turbine fuels hydrocarbon, respectively, at the reference state of 20 °C
and kerosene and indicates the tendency of a fuel to burn and 1 atm and where density must be in grams per cubic
with a smoky flame. A higher amount of aromatics in a centimetre. Ri is high for aromatics and low for naphthenic
fuel causes a smoky characteristic for the flame and energy compounds, whereas paraffins have intermediate Ri values.
loss due to thermal radiation. The smoke point (SP) is the Ri is a useful parameter for estimation of the composition
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maximum flame height at which a fuel can be burned in and sulfur content of petroleum fractions [2].
a standard wick-fed lamp without smoking. It is expressed
in millimeters, and a high SP indicates a fuel with low 4.18.3 Viscosity Gravity Constant
smoke-producing tendency [6]. Measurement of SP is Another parameter defined in the early years of petroleum
described under the ASTM D1322 (United States) or IP characterization is the viscosity gravity constant (VGC).
57 (United Kingdom) and ISO 3014 test methods. For the This parameter is defined based on an empirical relation
same fuel, the measured SP by the IP test method is higher developed between SUS viscosity and SG through a con-
than that measured by the ASTM method by 0.5–1 mm for stant. VGC is defined at two reference temperatures of 38 °C
SP values in the range of 20–30 mm [9]. SP can be best (100 °F) and 99 °C (210 °F) as [5]
estimated through PNA composition and various methods
of estimation of SP are given in ASTM Manual 50 [2].
10SG − 1.0752 log10 (V38 − 38)
VGC = (4.8)
4.18 Defined Characterization 10 − log10 (V38 − 38)
Parameters
There are several properties and characteristics that are
not directly measurable but are defined based on measured SG − 0.24 − 0.022 log10 (V99 − 35.5)
VGC = (4.9)
properties and are in some cases useful parameters to 0.755
determine the quality and properties of petroleum fluids.
where:
4.18.1 Watson (UOP) Characterization Factor, KW V38 = viscosity at 38 °C (100 °F) in SUS
Since the early years of the petroleum industry, a character- V99 = SUS at 99 °C (210 °F).
ization parameter to classify petroleum and identify hydro- Conversion factors between cSt and SUS are given in
carbon molecular types was desired that was defined based ASTM Manual 50 [2]. VGC varies for paraffinic hydrocar-
on measurable parameters. The Watson characterization bons from 0.74 to 0.75, for naphthenic hydrocarbons from
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88 Petroleum Refining and Natural Gas Processing

0.89 to 0.94, and for aromatic hydrocarbons from 0.95 to Hydrogen (H2), which has a CH value of zero, has a heating
1.13. The main limitation in use of VGC is that it cannot be value more than methane (CH4), and methane has a heating
defined for compounds or fractions with viscosities less than value more than any other hydrocarbon. Heavy aromatic
38 SUS (~3.6 cSt) at 38 °C. ASTM D2501 suggests calculation hydrocarbons that have high CH values have lower heating
of VGC using SG and viscosity in mm2/s (cSt) at 40 °C. values. In general, by moving toward lower CH value fuel,
not only do we have better heating value but also better and
4.18.4 Viscosity Index cleaner combustion of the fuel. It is for this reason that the
Another useful parameter, especially for lubricating oils, is use of natural gas is preferable to any other type of fuel, and
the viscosity index (VI), which shows the variation of vis- hydrogen is an example of a perfect fuel with zero CH value
cosity with temperature as an indication of the composition (CH = 0) whereas black carbon is an example of the worst
of viscous fractions. VI is an empirical number indicating fuel with a CH value of infinity [2]. Accurate values of CH
variation of the viscosity of oil with temperature. A low VI can be determined from the elemental analysis of a fuel.
value indicates a large variation of viscosity with tempera-
ture, which is a characteristic of aromatic oils. Similarly, 4.18.6 Correlation Index
paraffinic hydrocarbons have high VI values. The method The correlation index (CI), defined by the U.S. Bureau of
is described under ASTM D2270 and ISO 2909. In English Mines, is expressed by the following equation [6]:
unit systems, VI is defined in terms of viscosity at tem-
peratures 37.8 and 98.9 °C (100 and 210 °F). However, in SI 48, 640
CI = + 473.7SG − 456.8 (4.10)
units, viscosities at reference temperatures of 40 and 100 °C Tb
have been used to define the VI. Details of calculation of VI
are given in ASTM Manual 50 [2]. where Tb is the volume average boiling point (VABP) in K.
Values of CI between 0 and 15 indicate a predominantly par-
4.18.5 CH Weight Ratio affinic oil. A value of CI greater than 50 indicates a predomi-
CH is defined as the ratio of the total weight of carbon nance of aromatic compounds. CI has a tendency to increase
atoms to the total weight of hydrogen in a compound or with increasing boiling point in a given crude oil [6].
a mixture and is used to characterize a hydrocarbon com-
pound. At the same carbon number, the atomic ratio of the 4.19 Standard Methods
number of carbon (C) atoms to the number of hydrogen (H) There are several international organizations that are
atoms increases from paraffins to naphthenes and aromat- known as standard organizations and they recommend
ics. For example, n-hexane (C6H14), cyclohexane (C6H12), and specific characteristics or standard measuring techniques
benzene (C6H6) from three different hydrocarbon groups all for various petroleum products through their regular publi-
have six carbon atoms but have different CH atomic ratios cations. Some of these organizations in different countries
of 6/14, 6/12, and 6/6, respectively. If the atomic CH ratio that are known by their abbreviations are as follows [2]:
is multiplied by the ratio of the atomic weights of carbon • ASTM (American Society for Testing and Materials) in
(12.011) to hydrogen (1.008), then the CH weight ratio the United States. This is now known as ASTM Inter-
is obtained. For example, for n-hexane, the CH value is national (http://www.astm.org) and is based in West
calculated as (6/14) × (12.011/1.008) = 5.107. This number Conshohocken, PA.
for benzene is 11.92. Therefore, the CH weight ratio is a • ISO (International Organization for Standardization)
parameter that is capable of characterizing the hydrocar- (http://www.iso.org) is based in Geneva, Switzerland.
bon type. In addition, within the same hydrocarbon group, • Energy Institute (formerly IP) (http://uk.ihs.com/
the CH value changes from low to high carbon number. collections/ipbs/index.htm) is based in London, United
For example, methane has a CH value of 2.98 whereas pen- Kingdom.
tane has a CH value of 4.96. For extremely large molecules • API (American Petroleum Institute) (http://www.api
( M → ∞ ), the CH value of all hydrocarbons regardless of .org) is based in Washington, DC, in the United States.
their molecular type approaches the limiting value of 5.96. • AFNOR (Association Francaise de Normalisation)
This parameter can be used to estimate the hydrocarbon (http://www.afnor.org/) is an official standard organiza-
properties or the composition of petroleum fractions. In tion in France.
some references, the hydrogen-to-carbon (HC) atomic ratio ASTM is composed of several committees, in which a
is used as the characterizing parameter. According to the D committee is responsible for petroleum products and for
definition, the CH weight ratio and the atomic HC ratio are this reason its test methods for petroleum materials are
inversely proportional. The limiting value of the HC atomic designated by the prefix D. For example, the test method
ratio for all hydrocarbon types is 2 [2]. ASTM D2267 provides a standard procedure to determine
Another use of the CH weight ratio is to determine the the benzene content of gasoline. In France this test method
quality of a fossil-type fuel. Quality and the value of a fuel is designated by EN 238, which is described in AFNOR
are determined from its heat of combustion and heating information document M 15-023. Most standard test meth-
value. The heating value of a fuel is the amount of heat ods in different countries are very similar in practice but
generated by complete combustion of one unit mass of the they are designated by different codes. For example, the
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fuel. For example, n-hexane has the heating value of 44,734 international standard ISO 6743/0, accepted as the French
kJ/kg (19,232 Btu/lb) and benzene has the heating value of standard NF T 60-162, treats all of the petroleum lubri-
40,142 kJ/kg (17,258 Btu/lb). This is also known as the net cants, industrial oils, and related products. The abbrevia-
heat of combustion. Calculation of heating values is dis- tion NF is used for the French standard whereas EN is used
cussed in ASTM Manual 50. From this analysis it is clear for European standard methods. Most ISO test methods
that as the CH value increases the heating value decreases. are adopted from ASTM but are given a different code.
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Chapter 4 n Properties, Specifications, and Quality of Crude Oil 89

Table 4.3—Standard Test Methods for Measurement of Some Properties of Liquid

Petroleum Products [2]
Property ASTM D IP ISO Property ASTM D IP ISO
Aniline point 611 2/98 2977 Flash point 93 34/97 2719
CR (Ramsbottom) 524 14/94 4262 Freezing point 2386 16/98 3013
CR (Conradson) 189 13/94 6615 Hydrocarbon types 1319 156/95 3837
CN 4737 380/98 4264 Heating value 240
Cloud point 2500 219/94 3016 Kinematic viscosity 445 71/97 3104
Color 1500 196/97 2049 Octane number (MON) 2700 236/09 5163
Density/SG 4052 365/97 2185 Refractive index 1218
Distillation at 86 123/99a 3405 Pour point 97 15/95 3015
atmospheric pressure
Distillation at reduced 1160 6616a Sulfur content 1266 107/86 2192
pressures
Distillation by GC 2887 406/99a SP 1322 – –
Distillation of crude oils 2892 8708a Vapor pressure (RVP) 323 69/94 3007
Autoignition 2155 3988 Viscosity (viscous oils) 2983 370/85 a

a
Methods are similar but not identical to other standard methods.
Most IP methods are also used as British Standard under BS2000 methods.
The number after the IP number indicates the year of last approval.

Government regulations to protect the environment or to CH ratio, less sulfur and metals, and have lower CR and
save energy, in many cases, rely on the recommendation viscosity. For this reason, API gravity is used as the primary
by official standard organizations. For example, in France, parameter to quantify quality of a crude. API gravity of
AFNOR gives specifications and requirements for various crudes varies from 10 to 50; however, most crudes have an
petroleum products. For diesel fuels, it recommends (after API gravity between 20 and 45 [7]. A crude oil having an API
1996) that the sulfur content should not exceed 0.05 wt % gravity greater than 40 (SG < 0.825) is considered as a light
and the flash point should be greater than 55 °C [6]. Some crude whereas a crude with an API gravity less than 20 (SG
test methods (ASTM, ISO, and IP) for quality-related prop- > 0.934) is considered as a heavy oil. Crudes with API gravity
erties are given in Table 4.3 [2]. between 20 and 40 are called intermediate crudes. However,
this division may vary from one source to another and usu-
4.20 Crude Oil Assays ally there is no sharp division between light and heavy crude
Composition of a crude may be expressed similar to a reser- oils. Crude oils having an API gravity of 10 or lower (SG > 1)
voir fluid in terms of C1 through n-C5 as pure components, are referred as very heavy crudes and often have more than
C6 (hexanes), and C7+ (heptane-plus). A crude is produced 50 wt % residues. Some Venezuelan crude oils are from this
through reducing the pressure of a reservoir fluid to atmo- category. Another parameter that characterizes the quality
spheric pressure and separating light gases. Therefore, a of a crude oil is the total sulfur content. The total sulfur
crude oil is usually free of methane gas and has a higher content is expressed in weight percent and it varies from less
amount of C7+ than the original reservoir fluid. However, in than 0.1 % to more than 5 %. Crude oils with a total sulfur
many cases information on characteristics of crude oils are content of more than 0.5 % are termed as sour crudes, and
given through crude assay. Complete data on crude assay when the sulfur content is less than 0.5 % they are referred to
contain information on specification of the whole crude as sweet crudes [7]. After sulfur content, lower nitrogen and
oil as well as its products from atmospheric or vacuum metal contents signify the quality of a crude oil.
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distillation columns. The Oil & Gas Journal Data Book has
published a comprehensive set of data on various crude oils 4.21 Quality of Petroleum Products
from around the world [11]. Characteristics of two crude oils Methods presented in this chapter can be used to evaluate
from two different countries and their products are given in the quality of petroleum products from available parame-
Table 4.4. A crude assay data set contains information on ters. The quality of a petroleum product depends on certain
API gravity, sulfur and metal contents, kinematic viscosity, specifications or properties of the fuel to satisfy required
pour point, and RVP. In addition to boiling point range, API criteria set by the market demand. These characteristics
gravity, viscosity, sulfur content, PNA composition, and other are specified for the best use of a fuel (i.e., highest engine
characteristics of various products obtained from each crude performance) or for a cleaner environment while the fuel
are given. From information given for various fractions, boil- is in use. These specifications vary from one product to
ing point curve for the whole crude can be obtained. another and from one country to another. For example, for
Quality of crude oils are mainly evaluated based on a gasoline the quality is determined by a series of properties
higher value for the API gravity (lower SG); lower aromatic, such as sulfur and aromatic contents, octane number, vapor
sulfur, nitrogen, and metal contents; and lower pour point, pressure, hydrogen content, and boiling range. Engine
CH, viscosity, CR, and salt and water contents. Higher API warm-up time is affected by the percent distilled at 70 °C
crudes usually contain higher amounts of paraffins, a lower and ASTM 90 % temperature. For the ambient temperature
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90 Petroleum Refining and Natural Gas Processing

Table 4.4—Crude Assay Data for Two Oils [11]

Crude 1 Crude 2
Kuwaiti Crude Oil for Export Boscan, Venezuela
Mina Al Ahmadi Heavy Naphtha Gas Oil Bajo Grande Yield, vol %: 1.28 Aniline point,
Range, °F: 170–310 Range, °F: 680–1000 Lake Maracaibo Sulfur wt %: 1.88 °F: 117.3
Crude Yield, vol %: 11.91 Yield, vol %: 24.09 Aromatics, %: 24.04 Cetane index: 42.27
Gravity, °API: 31.4 Gravity, °API: 62.1 Gravity, °API: 21.4 Crude Pour point, °F:
Viscosity, SUS at 100 Sulfur, wt %: 0.03 Pour point, °F: +100 Gravity, °API: 10.10 –141.0 Residue
ºF: 58.1 Aniline point, °F: 136.2 Sulfur, wt %: 3.12 Sulfur, wt %: 5.5 SP, mm: 16.0 Range, °F: 650+
Pour point, °F: +5 Paraffins vol %: 70.1 Total nitrogen, Viscosity, SUS at Aniline point, °F: Yield, vol %: 82.9
Sulfur, wt %: 2.52 Monocycloparaffins, ppm: 900 100 °F: 90,000 112.69 Sulfur, wt %: 5.86
Ni/V (calcined), ppm: vol %: 20.4 Ni/V, ppm: <0.1/<0.1 Pour point, °F: +50 Gravity, °API: 6.10
8/30 Dicycloparaffins, Vis, SUS at 130 Gas Oil Sulfur, wt %: 5.86
RVP, psi: 6.7 vol %: 0.4 °F: 175.2 Light Naphtha Range, °F: 400–500 Ni/V, ppm: 175/1407
H2S, wt %: <0.001 Total aromatics, Ramsbottom CR, Range, °F: 82–200 Yield, vol %: 3.96 Kinematic viscosity
C1–C4 (GC analysis), vol %: 9.1 wt %: 0.47 Yield, vol %: 0.55 Gravity, °API: 34.0 at 122 °F: 22,502
vol %: 3.03 Sulfur, wt %: 3.14
Kerosene Residuum Heavy Naphtha Kinematic viscosity
Naphtha Range, °F: 310–520 Range (VEFV), °F: Range, °F: 200–300 at 122 °F: 1.81
Range, °F: Over Yield, vol %: 18.43 1,000+ Yield, vol %: 1.32 Pour point, °F:
point to 140 Gravity, °API: 45.9 Yield, vol %: 21.78 Sulfur, wt %: 0.68 –77.53
Yield, vol %: 3.80 Pour point, °F: –45 Gravity, °API: 5.8 Paraffins, %: 53.28 SP, °F: 16.11
Gravity, °API: 89.7 Sulfur, wt %: 0.39 Sulfur, wt %: 5.11 Aniline point, °F:
Sulfur, wt %: 0.04 Aniline point, °F: V/Ni, ppm: 116/34 Naphtha 113.83
RON (micro), clear: 142.9 Vis., SUV, Range, °F: 300–350 Cetane index: 37.24
71.8 Cetane index: 53.8 sec@250 °F: 3,394 Yield, vol %: 0.88
RON + 3 mL TEL: 89.3 SP, mm: 26 Ramsbottom CR, wt Sulfur, wt %: 1.28 Gas Oil
%: 21.9 Paraffins, %: 34.9 Range, °F: 500–550
Naphtha Heating Oil Yield, vol %: 2.66
Range, °F: 140–170 Range, °F: 520–680 Kerosene Gravity, °API: 28.62
Yield, vol %: 2.26 Yield, vol %: 14.89 Range, °F: 350–400 Sulfur, wt %: 4.02
Gravity, °API: 78.6 Gravity, °API: 32.9
Sulfur, wt %: 0.02 Viscosity, SUS at Gas Oil
Aniline point, °F: 147.7 100 °F: 43.3 Range, °F: 550–650
RON, clear/+3 mL Pour point, °F: +20 Yield, vol %: 6.46
TEL: 58.2/80.40 Total nitrogen, ppm: Gravity, °API: 25.54
Paraffins, vol %: 88.5 100 Sulfur, wt %: 4.47
Monocycloparaffins, Sulfur, wt %: 1.98 Pour point, °F: –10.9
vol %: 9.9 Aniline point, °F: 160.2 CN: 38.0
Total aromatics, vol Cetane index: 54.3
%: 1.6

of 26.7 °C (80 °F), a gasoline must have ASTM distillation of fraction to produce the required final product. For exam-
90 % distilled at 188 °C and 3 % distilled at 70 °C to give an ple, to increase the vapor pressure of gasoline, n-butane
acceptable warm-up time [7]. Standard organizations such may be added during the winter season to improve the
as ASTM give such specifications for various products. The
amount of particulate emissions is directly related to the 5HGXFWLRQ
aromatic and sulfur content of a fuel. Figure 4.3 shows
the influence of sulfur reduction in gasoline from 500 to
50 ppm in the reduction of pollutant emissions [8].
The vapor pressure of gasoline or jet fuel determines
their ignition characteristics. Freezing point is important
for jet fuels and gas oils. For lubricating oil, properties such
as viscosity and VI are important in addition to sulfur and
PAH composition. Aniline point is a useful characteristic
to indicate the power of solubility of solvents as well as
aromatic contents of certain fuels. For heavy petroleum

products, knowledge of properties such as CR, pour point,
and cloud point are of interest.
One of the techniques used in refining technology to
produce a petroleum product with a certain characteristic
is the blending method. Once a certain value for a prop- +& &2 12[
erty (i.e., viscosity, octane number, pour point, etc.) of a Figure 4.3—Influence of sulfur content in gasoline (from
petroleum product is required, the mixture may be blended 500 to 50 ppm) in the reduction of pollutant gases [2,8]. HC,
with a certain component, additive, or another petroleum hydrocarbon; CO, carbon monoxide; NOx, nitrogen oxide.
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Chapter 4 n Properties, Specifications, and Quality of Crude Oil 91

engine-starting characteristics of the fuel [7]. The amount The use of LPG as automotive fuel has increased over
of required butane to reach a certain vapor pressure value the years, prompting more strict specifications, for example,
can be determined through calculation of the vapor pres- propane HD-5, as given in Table 4.5. Table 4.6 compares the
sure blending index for the components, which is discussed specifications of automotive LPG and domestic LPG. The
in reference 2. composition and specifications of LPG vary depending on the
country, and different suppliers have come up with their own
4.22 Specifications of Various Fuels specifications of “autogas.” For example, Italy uses butane, the
Generally fuels are formulated specifically for different United Kingdom uses propane, and France uses a mixture of
cars, different parts of the world, and different markets. propane and butane as autogas. When used as a mixture, the
Some general specifications for fuels are providing higher fuel usually consists of 50 % propane and 50 % butane. Table
energy for power, forming a combustible mixture, easy igni- 4.7 shows the autogas specifications reported by Shell [14].
tion, minimizing harmful emissions, burning smoothly, and
protecting the fuel delivery system. In this section, we pres- 4.22.2 Gasoline Specifications
ent specifications recommended by international standard Gasoline is used as fuel in spark-ignition engines. The term
organizations and manufacturers for several fuels such “petrol” is still used in several countries to denote gaso-
as LPG, gasoline, jet fuel, diesel, marine fuel and middle line. Gasoline specifications have evolved considerably in
distillates, biodiesel, fuel oil, and petroleum coke. Tables the last 25 years and show significant variations among
4.5–4.20 list the current specifications for petroleum prod- countries in key properties such as octane number, vapor
ucts that rely on the designated properties and standard pressure, benzene, total aromatic sulfur content, and oxy-
methods that were introduced earlier in this chapter. genated compounds [15]. More changes are on the way to
increase fuel efficiency and to reduce pollutant emissions.
4.22.1 LPG Specifications In the United States, regulatory gasoline specifications
Liquefied petroleum gas (LPG) is a general term that enforced by the state governments and the U.S. Environ-
refers to propane (C3), butane (C4), or a mixture of the two mental Protection Agency (EPA) are guided by standard
with impurities such as ethane, pentane, hydrogen sulfide methods given by ASTM D4814. Some general specifica-
(H2S), and water. Propane, butane, and their mixtures are tions are as follows:
ideal fuels that can be stored and transported as liquids at • Maximum sulfur content = 0.03 wt %
ambient temperatures and moderate pressures. LPG has • Maximum lead content = 0.05 g Pb/gal
numerous applications because of its stability, high-energy • Oxidation stability = 240 min
content, relatively low sulfur content, and clean-burning • Maximum benzene content = 1.0 wt %
properties [12]. The U.S. Gas Processors Association (GPA) • Oxygen content = 1.5–4.0 wt %
specifies the properties for commercial LPG for propane, • VOC reduction of 21.4–23.4 %
butane, and their mixtures [13]. Table 4.5 lists the GPA • Maximum RVP = 6.4–15.0 psi
specifications for propane, butane, and propane-butane • Maximum distillation temperature for 10 % volume =
mixtures, including specifications for propane used as auto- 122–158 ºF, for 50 % volume = 230–250 ºF, and for 90 %
motive fuel (HD-5) [13]. volume = 365–374 ºF

Table 4.5—Specifications for Commercial Propane, Butane, and Propane-Butane Mixture [13]
Propane-Butane Propane, HD-5
Property Propane Butane Mixture Automotive Fuel
Main components Propane and propene Butane and butene Propane, propene, >90 % propane, <5 %
butane, butene propene
Maximum vapor pressure 1434 483 1434 1434
at 37.8 ºC, kPa
95 % boiling point at 100 –38 2 2 –38
kPa, T95, ºC
Butane and heavier, vol % 2.5 – – 2.5
Pentane and heavier, – 2 2 –
vol %
Oil stain observation Pass – – Pass
(ASTM D2158)
Residue on evaporation of 0.05 – – 0.05
100 mL (max), mL
Corrosion, copper strip No. 1 No. 1 No. 1 No. 1
(max)
Volatile sulfur, mg/m3 34 34 34 23
(max)
Moisture content (ASTM Pass – – Pass
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D2713-70
Free water content – None None –
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92 Petroleum Refining and Natural Gas Processing

Table 4.6—Shell Autogas Specifications (date revised June 9, 2009) [14]

Property Method Typical Value
Vapor pressure at 40 ºC, kPa ISO 4256:1996 800 min
ISO 8973:1997 1530 max
Volatile residue C5 and higher hydrocarbons, mol % ISO 7941:1998 2.0 max
Residue on evaporation, mg/kg JLPGA-S-05T/86 (105 °C) 20 max
Corrosion, copper strip ISO 6251:1996 Class 1
Sulfur, mg/kg ASTM D2784-98 100 max
Dienes, mol % ISO 7941:1998 0.3 max
Moisture content ISO 13758:1996 Pass
Free water Visual inspection Pass
MON ASTM D2699 90.5

Table 4.7—The CaRFG Phase Standards [15]

Property Flat Limits Averaging Limits Cap Limits Methods
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RVP, psi max

a
7.00 or 6.90 b
Not Applicable 6.40–7.20 ASTM D323-58 or 13
C.C.R. Section 2297
Sulfur, ppmw max 20 15 60c ASTM D2622-94 or ASTM
D5453-93
30c
20c
Benzene, vol % max 0.80 0.70 1.10 ASTM D5580-00
Aromatics, vol % max 25.0 22.0 35.0 ASTM D5580-00
Olefins, vol % max 6.0 4.0 10.0 ASTM D6550-00
T50, °F 213 203 220 ASTM D86-99
T90, °F 305 295 330 ASTM D86–99
Oxygen, wt % 1.8–2.2 Not Applicable 1.8 –3.5
d e
ASTM D4815-04
0d–3.5e
a
The RVP standards apply only during the warmer weather months.
b
The 6.90-psi flat limit applies when a producer or importer is using the CaRFG Phase 3 Predictive Model to certify a final blend not containing ethanol;
otherwise, the 7.0-psi limit applies.
c
The CaRFG Phase 3 sulfur content cap limits of 60, 30, and 20 ppm are phased in starting December 31, 2003, December 31, 2005, and December 31, 2011,
respectively.
d
The 1.8 wt % min oxygen content cap only applies during specified winter months in the areas identified in Section 2262.5(a).
e
If the gasoline contains more than 3.5 wt % oxygen from ethanol but no more than 10.0 vol % ethanol, the maximum oxygen content cap is 3.7 wt %.

• Maximum EP = 437 ºF monoxide and ozone nonattainment areas during certain

• Volatility temperature (V/L = 20) minimum = 105–124 ºF times of the year. RFGs have lower vapor pressure and lower
Fuel manufacturers report their own specifications in benzene, aromatic, and olefin contents. RFG specifications
compliance with federal and state government regulations. are mandated by federal law and implemented by EPA.
They usually provide Material Safety Data Sheets for safe In Europe, the European Commission sponsored the
and efficient use of fuels, especially on the main hazards Auto Oil Programme starting in the 1990s with the col-
such as fire. Fuels are also harmful or fatal if swallowed. laboration of Europia (the Association of European Oil
The three grades of gasoline usually sold in the United Companies) and ACEA (the Association of European Motor
States are regular grade with a posted octane [(R + M)/2] Manufacturers). This has culminated in the introduction of
level of 87, an intermediate grade with an octane level of new gasoline specifications that were implemented in two
89, and a super grade with an octane number between 93 stages starting in 2000 and 2005, respectively. The changes
and 94. Ethanol is used as an octane booster or for environ- in the specifications included lowering the limits for ben-
mental purposes in more than half of the gasoline sold in zene, sulfur, olefin, and total aromatic concentrations and
the United States. reducing the vapor pressure. Table 4.8 lists the current
Table 4.7 lists the California Reformulated Gasoline specifications for European Union Norm EN 228 [15,17]
specifications known as CaRFG Phase 3 standards as and ACEA Worldwide Fuel Charter Category 4 gasoline
mandated by the state law as of August 29, 2008 [15,16]. [15,18]. The standard methods used in measuring the listed
These standards are the most restrictive specifications in properties are also included in references 17 and 18.
the United States. Reformulated gasoline (RFG) was intro- Table 4.9 gives the specifications for unleaded gasoline
duced in the 1990s in the United States to be used in carbon use in the major cities in India [15,19]. There are plans
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Chapter 4 n Properties, Specifications, and Quality of Crude Oil 93

Table 4.8—Specifications for European Union Norm EN 228 Gasoline [17] and ACEA
Worldwide Fuel Charter Category 4 Gasoline [18]
European Union ACEA Worldwide Fuel
Property Norm EN 228 Charter Category 4 Gasoline
Octane rating, (RON + MON)/2 90 87–93
Vapor pressure, kPa 45–90a 45–60b
Sulfur concentration, ppmw max 10 10
Benzene concentration, vol % 1.0 1.0
Aromatic concentration, vol % 35.0 35.0
Olefin concentration, vol % 18.0 10.0
T50, °C – 77–100
T90, °C – 130–175
Percent evaporated at, vol %
70 °C (E70 summer) 20–48 –

70 °C (E70 winter) 22–50 –

70 °C (E70) – 20–45b
100 °C (E100) – 50–65b
150 °C (E150) 75 –
180 °C (E180 ) – 90
FBP, °C 210 195
Oxygen concentration, wt % 2.7c 2.7d
a
Range is from summer minimum (45 kPa) to winter maximum (90 kPa).
b
Absolute vapor pressures and distillation temperature points are for gasoline markets with ambient temperatures above 15 °C. Other limits
apply for markets with lower ambient temperatures.
c
Permitted max vol % oxygenates: methanol = 3 %, ethanol = 5 %, isopropanol = 10 %, isobutanol = 10 %, ethers (≥5 carbon atoms) = 15 %.
d
Where oxygenates are used, ethers are preferred. Where up to 10 vol % of ethanol is permitted by existing regulations, the gasoline must
meet all of the other limits above. Methanol is prohibited. Propanol and higher alcohols are limited to ≤0.1 vol %.

Table 4.9—Unleaded Gasoline Specifications for Urban Areas in India [19]

Property Regular Gasoline Limit Premium Gasoline Limit
Octane rating, (RON + MON)/2 86 90
Vapor lock index,a kPa 750–950 750–950
Sulfur concentration, ppmw max 150 150
Benzene concentration, vol % 1.0 1.0
Aromatic concentration, vol % 42.0 42.0
Olefin concentration, vol % 21.0 18.0
T90, °C 150 150
FBP, °C 210 210
Oxygen concentration, % wt 3.9 –
MTBE, vol % 15 15
a
Vapor pressures are expressed as vapor lock index (VLI), which is 10(RVP) + E70, where E70 is the vol % evaporated at 70 °C.

for lowering the maximum sulfur content from 150 to standards over sulfur, benzene, and lead and the ability to
50 ppmw in the near future. The standards for the rural require certain amounts of renewable fuels such as ethanol.
areas are more flexible. The voluntary national standard CGSB 3.5 for automotive
Table 4.10 gives the gasoline specifications developed gasoline was developed by the Canadian General Standards
by the national governments in Australia [15,20] and New Board (CGSB) to mandate the sulfur, benzene, and lead
Zealand [15,21]. The individual states in Australia and the limits as follows [15,22]:
regional councils may enforce their own standards. • Sulfur = 30 ppmw maximum
In Canada, gasoline quality has been monitored by pro- • Benzene = 1 vol % maximum
vincial governments since 2008, except for some national
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- • Lead banned completely
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94 Petroleum Refining and Natural Gas Processing

Table 4.10—Unleaded Gasoline Specifications for Australia [20] and New Zealand [21]
Property Australia National Standard [20] New Zealand National Standard [21]
Octane rating, (RON + MON)/2 88 90
Vapor pressure, kPa – 45–95a
Flexible volatility index,b kPa – 115 max
Sulfur concentration, ppmw max 50 150c
Benzene concentration, vol % 1.0 1.0
Aromatic concentration, vol % 42.0 42.0
Olefin concentration, vol % 18.0 18.0
Percent evaporated at, vol %
• 70 °C (E70 ) – 22–48
• 100 °C (E100) – 45–70
• 150 °C (E150) – 75
FBP, °C 210 210
Oxygen concentration, wt % 3.9 –
Ethanol, vol % 10 d
10e
a
Range is from summer minimum (45 kPa) to winter maximum (95 kPa).
b
Flexible volatility index is vapor pressure in kPa + 0.7(E70).
c
The New Zealand sulfur standard is 150 ppmw as of January 2008. However, it includes a statement that there is an “ultimate requirement of 10–15 ppmw.”

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
d
Permitted maximum vol % of oxygenates other than ethanol: ethers = 1 %, and tert-butanol = 0.5 %.
e
Permitted maximum vol % of oxygenates other than ethanol: total other oxygenates = 1 %.

Table 4.11—ASTM D1655-07 (July 1, 2007) Requirements for Jet A and Jet A-1
Specification ASTM Test Method Recommended Value
Appearance Visual Clear and bright
Aromatics, vol % (max) D1319 25
Total sulfur, wt % (max) D1266, D1552, D2622, D4244, D5453 0.3
Sulfur, mercaptan, wt % (max) D3227 0.003 (30 ppmw)
Distillation, 10 % recovery, ºC (max) D86 205
Flash point, ºC (min) D58, D3828 38
Density at 15 ºC (kg/m3) D1298, D4052 775–840
Vapor pressure (at 100 ºF), max, kPa D323, D5191 14–21
Freezing point, ºC (max) D2386, D7153, D7154 –40 (Jet A), –47 (Jet A-1)
Viscosity, cSt at –20 ºC (max) D445 8
SP, mm D1322 25
Naphthalene, vol % (max) D1840 3.0
Net heat of combustion, MJ/kg D3338, D4529 42.8

4.22.3 Jet Fuel Specifications glycol ethyl ether (EGEE) or ethylene glycol monomethyl
Jet fuel is used in jet and turboprop aviation engines; it ether (EGME), which are blended with methanol and usu-
is a kerosene-based fuel different from aviation gasoline ally have a boiling range of 127–140 ºC with a maximum
(avgas—a high-octane gasoline) that is used in smaller water content of 0.2 %.
piston-powered aircraft. Among the most important prop-
erties of jet fuel are the freezing point, density, sulfur con- 4.22.4 Diesel Fuel Grades and Specifications
tent, and SP. Jet A is a designation for commercial jet fuel Diesel fuel is used in compression-ignition engines; it is
used in the United States similar to Jet A-1 fuel, which is derived from the gas oil fraction of crude oil. Important
used outside of the United States. Table 4.11 gives ASTM properties include autoignition characteristics (CN or
D1655-07 (July 1, 2007) requirements for Jet A/A-1 fuel. cetane index), low-temperature performance (e.g., cloud
ExxonMobil gives a good summary of specifications for point and pour point), and sulfur content. ASTM D975-09a
various jet fuels around the world [23]. An engine manufac- covers seven grades of diesel fuel oils suitable for vari-
turer’s requirements for aviation fuel are given in Table 4.12 ous types of diesel engines. These grades are described in
[23]. Icing inhibitors used for jet fuels are based on ethylene Table 4.13. The sulfur grade Sxxx designation has been
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Chapter 4 n Properties, Specifications, and Quality of Crude Oil 95

Table 4.12—Engine Manufacturer’s Requirement for Aviation Fuel Wide-Cut

Kerosene (Pratt & Whitney, February 23, 2007)
Specification ASTM Test Method Recommended Value
Appearance – Clear and Bright
Aromatics, vol % (max) D1319 25
Total sulfur, wt % (max) D1266, D1552, D2622, D4244, D5453 0.3
Sulfur, mercaptan, wt % (max) D3227 0.005 (50 ppmw)
Distillation, 10 % recovery, ºC (max) D86 205
FBP (EP), ºC (max) D86 300
API gravity D287, D1298, D4052 37–57
Vapor pressure (at 100 ºF), max, psi D323 3
Freezing point, ºC (max) D2386, D5972 –40
Viscosity, cSt at –20 ºC (max) D445 8.5
Net heat of combustion, MJ/kg D240, D1405, D2382, D3338, D1322 25

Table 4.13—U.S. Diesel Fuel Grades According to ASTM D975-09a

Fuel Grades Description Max Sulfur (ppm)

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
No. 1-D S15 A special-purpose, light middle distillate fuel for use in diesel engine 15
applications requiring a fuel with 15-, 500-, or 5000-ppm sulfur (max),
No. 1-D S500 500
as indicated, and higher volatility than those provided by No. 2-D fuels.
No. 1-D S5000 5000
No. 2-D S15 A general-purpose, middle distillate fuel for use in diesel engines 15
requiring a fuel with 15-, 500-, or 5000-ppm sulfur (max), as indicated,
No. 2-D S500 500
especially suitable for use in applications with conditions of varying
No. 2-D S5000 speed and load. 5000

No. 4-D A heavy distillate fuel, or a blend of distillate and residual oil, for
low- and medium-speed diesel engines in applications involving
predominantly constant speed and load.

adopted to distinguish grades by sulfur. S5000 grades European Commission’s Auto-Oil II draft proposal fell short
correspond to the previous “regular” sulfur grades No. of recommendations by most of the Northern European
1-D and No. 2-D. S500 grades correspond to the previous member states (Scandinavia) to require 100 % 10-ppm
“low-sulfur” grades. S15 grades were not included in the ULSD by 2007/2008. The situation in the United States is
previous grade system and are commonly referred to as somewhat different. The U.S. Department of Energy said it
“ultralow sulfur” grades. would be unwise to set a 15-ppm sulfur cap until catalyst
Table 4.14 compares specifications of No. 2 diesel fuel developers determine maximum sulfur tolerance for nitro-
in the United States (according to ASTM D975) and Europe gen oxide (NOx) traps combined with particulate matter
(EN 590–2005). (PM) traps, the technology of choice in EPA’s diesel emis-
The European Commission’s latest “Auto-Oil II” discus- sions regulatory scheme.
sion paper proposed that a 10-ppm sulfur ultralow sulfur One report shows that in Europe in 1998, approxi-
diesel (ULSD) be gradually phased in, starting with a 10 % mately one third of countries were using diesel fuel with
supply requirement on January 1, 2007. This 10-ppm fuel was a sulfur content of 0.05 % (500 ppm); within 3 years this
a phase-in alongside a 50-ppm sulfur ULSD that became man- number had reduced to less than one quarter. Use of ULSD
datory throughout Europe in 2005. It was suggested that the is spreading; for example, one of the South African diesel
10-ppm sulfur ULSD supply mandate would jump to a mini- fuel samples found in the survey also was a near-zero-
mum of 25 % in 2011, although individual countries could sulfur ULSD, although South Africa does not require such
petition for 3-year derogation of the 25 % mandate if they fuel. The same report shows that Korea and Singapore
could prove no benefits in greenhouse gas reductions [24]. have sharply cut diesel sulfur limits, and similar trends
European governments earlier agreed that highway are expected throughout the Asia Pacific region. Specifica-
diesel sulfur be cut to 50 ppm starting in 2005, but they left tions are tightening in an effort to reduce smoke produc-
it to the Auto-Oil II program to recommend other specification, particularly in China, Malaysia, and India. Despite
tions for cetane, distillation, density, and polyaromatic lim- these new density/distillation limits, cold flow performance
its. The European Commission had also agreed to consider remains essentially unchanged across all regions. However,
whether all ULSD should drop from 50- to 10-ppm sulfur one problem associated with sulfur reduction is a drop in
in 2008, as was recommended by Germany. However, the fuel lubricity, which refineries should address by adding
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96 Petroleum Refining and Natural Gas Processing

Table 4.14—Specifications for U.S. Diesel Fuel No. 2-D S15 and Europe EN 590 (2005) [25]
United States, ASTM D975 –09a Europe, EN 590 (2005)
ASTM Test Recommended IP Test Recommended
Specification Method Value Method Value
Flash point, ºC (min) D93 52 IP 404 55
Water and sediment, vol D2709 0.05 ISO 12937 0.02
% (max)
Distillation temperature, D86 T90, 282/338 ISO 3405 T85, 350 (max)
ºC, at vol % vaporized (min/max) T95, 360 (max)
Kinematic viscosity, D445 1.9/4.1 IP 71 2.0/4.5
(mm2/s) at 40 ºC (min/max)
Ash, wt % (max) D482 0.01 IP 4 0.01
Sulfur, ppmw (max) D2622 15 IP 336 50
CN, min D613 40 ASTM D613 51

Table 4.15—Requirements for Three Types of Marine Distillate Fuels in Europe [27]
Property Test Method Category A Category B Category C
Density at 15 °C, kg/m 3
ISO 3675 890 900 920
Viscosity at 40 °C, mm2/s ISO 3140 6.0 11.0 14.0
Flash point, °C (min) ISO 2719 60 60 60
Pour point, °C (max)
Winter quality ISO 3016 –6 0 0
Summer quality 0 0 6
Sulfur, % ISO 8754/ISO 14596 1.5 2 2
Cetane index (min) ISO 4264 40 35 –
CR (max) ISO 10370 0.3 0.3 2.5
Ash, wt % (max) ISO 6245 0.01 0.01 0.03
Appearance Visual Clear and bright
Water, % (vol/vol) ISO 3733 – 0.3 0.3
Vanadium, ppmw (mg/kg) ISO 14597 (IP 501) – – 100
Aluminum plus silicon ISO 10478 (IP 501) – – 25

lubricity additives. Between 1998 and 2001, the average CN and Table 4.16 shows Indian (IS 15670), U.S. (ASTM
of diesel fuels jumped from 50.6 to 54.6 according to the EN D6751), and European (EN 14214) biodiesel standards.
590 specifications [26].
An ASTM standard (D2069) was used to cover different 4.22.6 Fuel Oil (Heating Oil) Grades and
marine diesel fuels, but it has been withdrawn. Techni- Specifications
cally, it was equivalent to ISO 8217. Table 4.15 gives some Fuel oil is burned to generate heat for different applica-
requirements for three types of marine fuels in Europe [27]. tions ranging from space heating to electricity genera-
The user’s requirement will always be that the burner fuel tion. Different types of burners used in these applications
should be safe to handle and easy to transfer; be capable of require different grades of fuel oils. ASTM D396 divides
being adequately cleaned of catalyst fines, dirt, and water; fuel oils into five different grades designated as No. 1, 2,
and should be noncorrosive. ISO 8217 standard does cover 4, 5, and 6. Table 4.17 lists these grades along with their
these properties for marine distillate fuels. common uses and significant properties [29]. In general,
all grades of fuel oils should be homogeneous hydrocarbon
4.22.5 Specification of Biodiesels liquids free from inorganic acid and excessive foreign solid
Technically, biodiesel is a fuel comprised of monoalkyl matter.
esters of long-chain fatty acids derived from vegetable oils Table 4.18 lists some specifications for the different
or animal fat that meets prevailing standard specifications grades of fuel oils. The viscosity values given in parentheses
[28]. Various countries have their own biodiesel standards, are for information only, not necessarily limiting.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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Chapter 4 n Properties, Specifications, and Quality of Crude Oil 97

Table 4.16—Common Uses and Some Significant Properties of Different

Grades of Fuel Oils [28]
Grade Classification Application Significant
Properties

No. 1 Distillate Domestic and small Volatility and pour

industrial burners of the point
vaporizing type

No. 2 Distillate Atomizing-type domestic Volatility and

and small industrial viscosity
burners

No. 4 (light) Heavy distillate Pressure-atomizing-type Viscosity and pour

commercial/industrial point
burners

No. 4 Heavy distillate, distillate/ Pressure-atomizing-type Viscosity, flash

residual blends commercial/industrial point, and sulfur
burners; preheating not content
required for handling or
burning

No. 5 (light) and No. 5 Residual Industrial burners; Viscosity, flash

(heavy) preheating may be point, and sulfur
required for handling and content
burning

No. 6 or Bunker C Residual Industrial burners; Viscosity, flash

preheating required for point, and sulfur
handling and burning content

Table 4.17—Some Specifications for Fuel Oils (ASTM D396)

Properties No. 1 No. 2 No. 4 No. 5 No. 6
SG, 60/60 °F 0.8499 0.8762 – – –
°API 35 min 30 min
Flash point, 38 38 55 55 60
°C min
Pour point, –18 –6 –6 – –
°C max
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Kinematic viscosity, mm2/s (cSt)

At 40 °C (104 °F) min 1.3 1.9 5.5 –
max 2.0 3.4 24.0 – –
At 50 °C (100 °F) min – – – 5.0 15.0
max – – – 5.0 50.0

Distillation temperature, °C
10 % point max 215 –
90 % point min – 282
max 288 338
Sulfur content, mass, max 0.5 0.5
Corrosion copper strip, max 3 3
Sulfated ash, % mass, max 0.10 0.15
Water and sediment, vol %, max 0.05 0.05 (0.50) (1.00) (2.00)

4.22.7 Classification and Properties of or from delayed coking of fluid catalytic cracking (FCC)
Petroleum Coke decant oil to produce needle coke. Table 4.19 shows an
Petroleum coke is generally defined as a solid carbonization overall classification of green petroleum cokes (sponge,
product from delayed coking or fluid coking of vacuum fuel, shot, needle, and fluid coke) and their industrial appli-
distillation residua to produce sponge coke (or fluid coke), cations [29].
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98 Petroleum Refining and Natural Gas Processing

Table 4.18—Various Biodiesel Standards Applicable in India, United States, and

Europe [28]
Property BIS (IS 15670 ) ASTM D6751 EN 14214
Density at 15 °C, kg/m3 860–900 – 860–900
Kinematic viscosity at 40 °C, cSt 2.5–6.0 1.9–6.0 3.5–5.0
Flash point (PMCC) °C, min 120 93 (Closed Cup) >101
Sulfur, ppm (max) 50 15 10
CR, % by mass 0.05 0.05 (max) 0.3
Water content and sediment 500 mg/kg 0.05 vol % (max) 500 mg/kg
Total contamination, ppm (max) 24 24 24
Sulfated ash content, % (m/m) 0.02 200 ppm (max) 0.02
Copper strip corrosion (3 h at 50 °C) Class 1 (max) Class 3 Class 1 (max)
CN, min 51 47 51
Acid value, mg KOH/g 0.5 0.50 0.5
Iodine value NA NA 120
Free glycerol, % mass (max) 0.02 0.020 0.02
Total glycerol, % mass (max) 0.25 0.240 0.25
Oxidation stability at 110 °C (h) (max) 6 3 6
Phosphorous, mg/kg 10 10 ppm (max) 10
Alkaline metals NA <5 ppm Group I (Na, K) <5 mg/kg Group I (Na, K)
<5 ppm Group II (Ca, Mg) <5 mg/kg Group II (Ca, Mg)
NA, not applicable.

Table 4.19—Coking Processes, Feedstocks, and Commercial Uses of

Petroleum Coke [29]
Process Product Commercial Uses of Coke
Delayed coking Sponge coke Carbon anodes for aluminum industry
Fuel coke Fuel for cement kilns, industrial heat and steam raising,
fuel for utility industry
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Shot coke No significant commercial use, some niche applications

(e.g., TiO2 production), packing material
Needle coke Graphite electrodes for electric-arc furnaces for iron and
steel industry
Fluid coking Fluid coke Industrial heat and steam raising
Flexi-coking Fluid coke, or fuel gas Industrial heat and steam raising

Petroleum cokes produced by delayed or fluid coking anode and graphite manufacture [29]. Not all green cokes
are generically called green cokes because of their relatively produced by delayed coking of vacuum distillation residua
high volatile matter content (5–15 %). Fluid cokes gener- are suitable for calcination. Depending on their sulfur and
ally have lower volatile matter content than delayed cokes metal contents, noncalcinable delayed cokes or fluid cokes
(typically ~5 %) because of the relatively high temperatures are used as fuel in industrial furnaces.
used in fluid coking. The flexi-coking process is a variation
of fluid coking in which part or the entire coke product can 4.23 Minimum Laboratory Data
be gasified to produce fuel gas. This is particularly useful for As discussed earlier, measurement of all properties of vari-
high-sulfur- and high-metal-content cokes that are not suit- ous petroleum fractions and products in the laboratory is
able for combustion. Green cokes with relatively low sulfur, an impossible task because of the required cost and time.
metal, and ash contents are calcined (i.e., heat treated to However, there are several basic parameters that must be
~1300 °C) to remove volatile matter. Calcined coke has a known for a fraction to determine various other proper-
mass fraction of hydrogen less than 0.1 %. Calcined cokes ties needed for design, operation, and quality of a fuel. For
are used as fillers for carbon anodes, graphite electrodes, example, to estimate sulfur content of a fraction, the input
or specialty carbons. Table 4.20 lists the specifications of parameters of SG, molecular weight, density, and refrac-
calcinable green cokes and calcined cokes used in carbon tive index at 20 °C are needed [2]. If experimental values of
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Chapter 4 n Properties, Specifications, and Quality of Crude Oil 99

on design calculations. The basic laboratory data that are

Table 4.20—Typical Green and Calcined Coke useful in characterization methods on the basis of their
Specifications [29] significance and simplicity are as follows:
Property Green Coke Calcined Coke • Distillation data, boiling point
Ash 0.1–1.0 % 0.2–1.5 % • SG
• Composition (i.e., PNA content)
Calcium 25–500 ppm 25–500 ppm
• Molecular weight
Fixed carbon 87–97 % 97–99 % • Refractive index
Hydrogen 3.0–4.5 % <0.1 % • Elemental analysis (i.e., C, H, and S composition, metal
Iron 50–2000 ppm 50–2000 ppm composition, etc.)
• Kinematic viscosity at 37.8 and 98.9 °C (100 and 210 °F)
Manganese 2–100 ppm 2–100 ppm
Using these properties, various physical properties

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Magnesium 10–250 ppm 10–250 ppm can be estimated with a good degree of accuracy. How-
Moisture 0.5–2.0 % Negligible ever, specific properties that are characteristic of each
Nickel 10–100 ppm 10–100 ppm quality product should be measured in addition to the
above properties. For example, for diesel fuel, cetane index
Nitrogen 0.1–0.5 % <0.1 %
should be measured, whereas for motor and aviation gaso-
Real density 1.6–1.8 g/cm3 2.08–2.13 g/cm3 line, octane number needs to be known. Freezing point
Silicon 50–300 ppm 50–300 ppm must be known for jet fuels, whereas pour point is needed
for heavy products as discussed above for each specific
Sulfur 0.2–2.5 % 0.2–2.5 %
property.
Titanium 2–60 ppm 2–60 ppm
Vanadium 5–500 ppm 5–500 ppm References
Volatile matter 5–15 % <0.5 % [1] ASTM, Annual Book of ASTM Standards, ASTM International,
West Conshohocken, PA, 2005.
[2] Riazi, M.R., “Characterization and Properties of Petroleum
Fractions,” MNL5, ASTM International, West Conshohocken,
all of these parameters are available, then a good estimate PA, 2005.
of sulfur content can be obtained. However, because all of [3] Private communication with James F. McGehee of UOP, Des
these data are not normally available, M, n, and d20 should Plaines, IL, May 21, 2009.
be estimated from SG and Tb. Therefore, a minimum of [4] ASTM Standard D6352: Standard Test Method for Boiling
Range Distribution of Petroleum Distillates in Boiling Range
two parameters (i.e., boiling point and SG) are needed to from 174 to 700 °C by Gas Chromatography, Annual Book of
estimate the sulfur content. However, for heavy fractions ASTM Standards, ASTM International, West Conshohocken,
in which distillation data are not reported, M should be PA, 2004.
estimated from kinematic viscosity at 38 and 99 °C (n38 and [5] API Technical Data Book—Petroleum Refining, 6th ed., T.E.
n99) and SG. Once M is estimated, n can be estimated from Daubert, R.P. Danner, Eds., American Petroleum Institute
(API), Washington, D.C., 1997.
M and SG and density at 20 °C is estimated directly from
[6] Speight , J.G., The Chemistry and Technology of Petroleum, 3rd
SG. With the knowledge of M and SG, all other parameters ed., Marcel Dekker, Inc., New York, 1998.
can be estimated from methods presented in ASTM Manual [7] Gary, J.H., Handwerk, G.E., and Kaiser, M.J., Petroleum Refin-
50 [2]. Therefore, at least three parameters (i.e., n38, n99, and ing, Technology and Economics, 5th ed., Marcel Dekker, Inc.,
SG) must be known to determine sulfur content or other New York, 2007.
characteristics. In the case that only one viscosity value is [8] Wauquier, J.-P., Petroleum Refining, Vol. 1 Crude Oil, Petroleum
Products, Process Flowsheets, Editions Technip, Paris, 1995.
known (i.e., n38), the n99 may be estimated from SG. In this
[9] Baird, C.T., Crude Oil Yields and Product Properties, Geneva,
way, the estimated value of M is less accurate than when Switzerland, 1981.
the values of n38, n99, and SG are known from experimental [10] Denis, J., Briant, J., and Hipeaux, J.C., Lubricant Properties
measurements. We see that again for heavy fractions Analysis & Testing, G. Dobson, trans., Editions Technip, Paris,
with knowledge of only two parameters (i.e., n38 and SG France, 1997.
or n99 and SG) all basic properties of the fraction can be [11] Oil and Gas Journal Data Book, 2000 edition, PennWell, Tulsa,
OK, 2000, pp. 295–365.
estimated. Therefore, to obtain the basic characterization
[12] Falkiner, R.J., “Liquified Petroleum Gas,” Fuels and Lubri-
parameters of a petroleum fraction, a minimum of two cants Handbook: Technology, Properties, Performance, and
parameters are needed. Testing, MNL37, ASTM International, West Conshohocken,
With the knowledge of PNA composition a better PA, 2003, pp. 31–53.
characterization of a fraction is possible through available [13] Liquified Petroleum Gas Specifications and Test Methods, Pub-
techniques. Therefore, if the composition along boiling lication 2140, Gas Processors Association, Tulsa, OK, 1997.
[14] “Shell Autogas Properties,” http://www.shell.com/home/
point is available, nearly all other parameters can be deter- content/au-en/shell_for_motorists/fuels/autogas/autogas_
mined through mid-boiling point and PNA composition properties_0821.html.
with better accuracy than using only boiling point and SG. [15] “Gasoline,” http://en.citizendium.org/wiki/Gasoline.
For heavy fractions in which Tb may not be available, the [16] “California Reformulated Gasoline Phase 3 Specifications,”
best alternative parameter is to measure M and PNA com- http://www.arb.ca.gov/fuels/gasoline/gasoline.htm.
position. Because there are many scenarios to estimate the [17] “European Union Norm EN 228 for Gasoline,” http://www
.biofuels-platform.ch/en/infos/en228.php.
basic properties of petroleum fractions, use of available
[18] “ACEA Worldwide Fuel Chapter,” http://www.acea.be/images/
data to predict the most accurate characterization param- uploads/pub/Final WWFC 4 Sep 2006.pdf.
eters is an engineering art that has a direct effect on the [19] “India Gasoline Specifications,” http://www.apecconsulting
subsequent prediction of physical properties and eventually .com/PDF/WebProductQualitySample.pdf.
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100 Petroleum Refining and Natural Gas Processing

[20] “Gasoline Specifications for Australia,” http://www.environment. [26] Peckham, J., “2/3 of World’s Diesel Fuel Now Low-Sulfur:
gov.au/atmosphere/fuelquality/standards/petrol/index.html. Infineum Survey,” March 5, 2001, http://findarticles .com/
[21] “New Zealand Gasoline Specifications,” http://www.med.govt.nz/ p/articles/mi_m0CYH/is_5_5/ai_718363363/.
templates/MultipageDocumentPage____ 10182.aspx#P437_17784. [27] Fabrick, W., “Updating ISO 8217,” International Fuel Execu-
[22] “Gasoline Specifications for Canada,” http://www.visiondurable tive Testing Services, World Bunkering, United Kingdom, 2005.
.com/media/pdf/ressources/etudes/Fuel_Quality_ in_Canada_-_ [28] Agrawal, A.K., Bajaj, T.P., “Process Optimisation of Base
Final_Report.pdf. Catalysed Transesterification of Karanja Oil for Biodiesel
[23] Warren, K.A., World Jet Fuel Specifications, ExxonMo- Production,” Int. J. Oil, Gas Coal Technol., Vol. 2, 2009,
bil Publication, Fairfax, VA, 2008, http://www.exxonmobil pp. 297–310.
.com/AviationGlobal/Files/WorldJetFuelSpecifications2005. [29] Eser, S., and Andrésen, J., “Properties of Fuels, Petroleum
pdf. Pitch, Petroleum Coke, and Carbon Materials,” Fuels and
[24] Peckham, J., “European Commission Proposes 10 ppm Lubricants Handbook: Technology, Properties, Performance,
ULSD Phase-In from 2007,” http://findarticles.com/p/articles/ and Testing, MNL37, ASTM International, West Conshohocken,
mi_m0CYH/is_5_5/ai_71836375/. PA, 2003, pp.757–786.
[25] “Diesel Fuel,” http://www.adb.org/Documents/Guidelines/
Vehicle.../cf_ch04.pdf.
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5
Crude Oil Refining Processes
Semih Eser1 and M.R. Riazi2

5.1 A Brief Historical Perspective of separated to produce approximately 3 bbl of gasoline from
Crude Oil Refining 200 bbl of charge. The remaining crude in the still was
Petroleum in the past century and present time has been the removed as tar and heavy fuel. The process took 24 h, and
major fossil fuel that provides most of the energy consumed after each run the still had to be cleaned. Coal was used
by humans. For this reason, the last 100–150 years are as fuel to heat the oil. Today’s refineries can produce more
referred to as the “Oil Century,” or “Petroleum Era” [1]. It than 50 bbl of gasoline from each 100 bbl of crude through
seems that at least for the present century, petroleum either chemical changes in the crude composition. This develop-
in the form of liquid crude oil or natural gas will remain as ment indicates how the refining industry has advanced
a major source to meet the world energy demand. The use over the last century, particularly with the introduction of
of petroleum and its derivatives has a long history. Sumeri- thermal and catalytic conversion processes.
ans, Assyrians, and Babylonians used crude oil and asphalt Until the early 1940s, most petroleum refineries in the
found in natural seeps more than 5000 years ago. Around United States comprised just atmospheric crude oil distil-
500 BC, Egyptians used asphalt for mummification of their lation units. More advanced refineries also had vacuum
dead rulers. Some 2000 years ago, Arab scientists developed distillation units and simple thermal cracking units such as
methods for the distillation of petroleum, and these meth- visbreakers. World War II and the burgeoning air transpor-
ods were introduced to Europe by way of Spain. Discovery tation industry created demand for a higher quantity and a
of distillation led to fractionation of petroleum into various higher quality of motor and aviation gasoline. Many of the
products such as naphtha (or naft), and it was used as an refining processes that constitute today’s complex refiner-
illuminant [1]. Greeks also used petroleum products known ies were often developed through collaboration between
as Greek fire in warfare. Marco Polo (13th century) reported the oil companies in the 1940s. These processes became
on the petroleum industry in the Baku region of northern commercially available within 5–10 years after the end
Persia (now part of Azerbaijan). Although petroleum has of the war and caused a rapid growth of the worldwide
been known for many centuries, the strong demand for petroleum industry with the increasing demand for distil-
kerosene to substitute for whale oil as an illuminant led to late fuels, gasoline, jet fuel, and diesel. Up until the 1970s, a
the birth of the modern petroleum technology and refining. principal focus in refining was to improve the performance
In an effort to secure a reliable supply of kerosene, a group characteristics of the fuels, such as the octane number for
of investors in Pennsylvania charged E.L. Drake to drill for gasoline. Environmental regulations on petroleum fuels
petroleum, and he completed the first commercial oil well introduced mostly through the environmental legislation in
in 1859 in Titusville, PA, in the United States [1]. the 1970s have focused on reducing the heteroatom content
The first refinery in the United States was built near of fuels, particularly that of sulfur species, placing limits on
Oil Creek, PA, in 1860 by William Barnsdall and William the air emissions of designated pollutants from combustion
H. Abbott. By 1870, a basic operating pattern had been [2]. Recent trends in refinery configurations include adding
developed to produce more kerosene for lamps and more capacity and processes to convert heavier (lower API grav-
lubricant for steam engines from the remainder of the ity) and dirtier (higher heteroatom content) crude oils into
crude. In 1876, Chevron built a simple refinery in California. increasingly cleaner fuels as designated by environmental
Stills were used to heat 25–40 bbl/day of crude to produce regulations. This has increased the significance of catalytic
kerosene, lubricants, waxes, and gasoline, which was consid- processes and catalyst development as well as the demand
ered a useless byproduct at the time. In the early 1900s, the for hydrogen, which is used in hydrotreating and hydro-
demand for kerosene decreased with the advent of electric cracking processes, as described in the following sections.
light, but the introduction of the internal combustion
engine and mass production of automobiles created a large 5.2 Objectives of Crude Oil Refining
demand for gasoline. In the early days of the petroleum An overall objective of a petroleum refinery is to add value
industry in the United States, oil was processed in simple to a crude oil feed through production of marketable fuels
batch distillation units [1]. For each distillation run, 200 and materials at the lowest possible cost in accordance with
bbl of oil were charged into stills, and the oil temperature product specifications and environmental regulations. In
was raised to 750°F. The produced vapors were condensed technical terms, achieving this objective generally depends
in two-stage condensers: one with reflux and the second on the composition and properties of the selected crude as
without reflux cooled by water. Gases in the product were well as the configuration of refinery processes.

1
The Pennsylvania State University, University Park, PA, USA
2
Kuwait University, Kuwait
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101
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102 Petroleum Refining and Natural Gas Processing

Considering that the products that are in high demand through different types of processes that eventually lead to
are light and middle distillates such as gasoline, jet fuel, and commercial fuels and materials, including liquefied petro-
diesel, and these fuels have higher H/C ratios than crude oils, leum gas (LPG), motor gasoline, jet fuel, diesel fuel, fuel
the two processing pathways for crude oil refining include oil, solvents, lubrication oils, asphalt, and coke. The key
carbon rejection and hydrogen addition. properties and specifications of these fuels and materials are
A refinery configuration should incorporate an optimal discussed in Chapter 2. The four groups of processes that
combination of the two pathways in separation and conver- are shown in Figure 5.1 are introduced and discussed in the
sion processes to achieve the overall refinery objective. A following sections, starting with the separation processes.
multitude of economic factors that may be unique to a given
refinery (e.g., crude oil market, product markets, capital 5.3.1 Separation Processes
cost, etc.) must be considered in setting up specific refinery Separation processes are physical processes that rely on
objectives. Any discussion of refinery economics is beyond specific physical properties of crude oils or their compo-
the scope of this chapter. However, it may be pointed out nents to fractionate or isolate their constituents. The most
that because of the volatility of crude oil prices and fluctua- prominent physical separation process in a refinery is the
tions in product demands, operational flexibility in terms of crude distillation process, which fractionates a crude oil
a refinery’s capability to process a wide range of crudes and into several cuts with respect to their boiling points that
to adjust the product slate according to the prevailing prod- range from gases at ambient conditions (e.g., propane and
uct markets has become a critical factor to realize the refin- butane that constitute LPG) to heavy vacuum gas oils that
ery objectives. This requires the optimization of each refinery have end points (higher boiling point of a distillation cut)
process within an optimal integration of all of the processes of approximately 1000°F. Distillate fractions of crude oil
to achieve the desirable product slate at the lowest cost. A that are directly sent to a finishing step or require minimal
general description of overall refinery flow and the intro- processing before entering a product pool are designated
duction of major refinery processes follow in Section 5.3. by the phrase “straight-run,” such as straight-run naphtha,
straight-run kerosene, etc. The higher boiling crude oil
5.3 Overall Refinery Flow fractions and the distillation residua obtained from the
In a refinery, crude oil is transformed into commercial atmospheric distillation and vacuum distillation towers are
fuels and materials using an integrated sequence of different sent to subsequent separation and conversion processes as
processes that can be classified into four categories: separa- described in the overall flow diagram to produce the desired
tion, conversion, finishing, and supporting. Figure 5.1 shows fuels and materials. In addition to boiling points, other
an overall refinery flow diagram starting with the crude oil physical properties of crude oil components can be used
entering a refinery at the top left and its generic progression for separation purposes, such as solubility/insolubility in a

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Figure 5.1—An overall refinery block flow diagram indicating an integrated network of major separation, conversion, finishing,
and supporting processes.
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Chapter 5 n Crude Oil Refining Processes 103

solvent (e.g., in desalting to remove salt from crude oil and in depending on the severity of thermal cracking used in the
deasphalting to separate asphalt from vacuum distillation process. On the other hand, coking involves a high-severity
residue) and freezing point (e.g., in dewaxing to separate thermal cracking to reject carbon in substantial quantities
wax to decrease the freezing point of the dewaxed oil). to produce a carbon-rich solid byproduct (coke) along with
light and middle distillates that are sent to finishing processes
5.3.2 Conversion Processes to contribute to the respective distillate fuel pools.
Because separation processes do not produce the desired
yields of particularly the distillate fuels (e.g., gasoline, jet 5.3.3 Finishing Processes
fuel, and diesel fuels) as premium products, conversion pro- Finishing processes constitute the final step in the process-
cesses are used to induce chemical changes in the composi- ing history of a commercial product to ensure that it meets
tion of crude oil fractions. In U.S. refineries, fluid catalytic the specifications for marketing. These processes, depicted in
cracking (FCC) processes are particularly important because generic terms in the boxes on the right-hand side of Figure 5.1
of their capability to produce high-octane number motor for each product, include physical mixing of different refinery
gasoline in high yields from the straight-run gas oil and streams in proportions to satisfy the product specifications
light vacuum gas oil. Other catalytic conversion processes (e.g., octane number and Reid vapor pressure for gasoline,
include catalytic reforming, catalytic isomerization, alkyla- cetane number, and pour point for diesel fuel), sweetening to
tion, and polymerization processes to further increase the remove sulfur compounds by absorption in basic solutions,
yields of high-octane number motor gasoline. In contrast to chemical reactions such as hydrotreatment to remove hetero-
catalytic cracking, which is aimed at reducing the molecular atoms (e.g., S, N, and metals), sweetening to convert certain
size of the compounds in the feed, catalytic isomerization sulfur species (i.e., mercaptans) into more benign sulfur com-
and catalytic reforming do not change the size of the feed- pounds (i.e., disulfides), and hydrogenation to saturate olefins
stock molecules to any significant extent. Catalytic reform- to the desired levels for storage stability of gasoline and to sat-
ing and isomerization processes increase the octane number urate aromatics to increase the cetane number of diesel fuel.
of their products through dehydrogenation of cycloalkanes
and isomerization of n-alkanes to produce aromatic hydro- 5.3.4 Supporting Processes
carbons (in reformate) and branched alkanes (in reformate Unlike the three categories of processes described above,
and isomerate). On the other hand, alkylation and polymer- support processes do not directly involve the production of
ization processes are used to induce the coupling (combina- hydrocarbon fuels or materials, but they do play critical roles
tion) of smaller hydrocarbons, such as one i-alkane (e.g., in the operation of a refinery. Support processes include
i-butane) and one olefin (e.g., propene), in alkylation and hydrogen production for supplementing hydrogen output
two olefins (e.g., i-butene and propene) in polymerization from catalytic reforming to meet the hydrogen demand
to produce i-alkanes and branched olefins, respectively, for hydrotreatment, hydrocracking, and hydrogenation
to obtain high-octane number molecules that boil in the processes; acid gas removal to separate hydrogen sulfide
gasoline range. Therefore, the lighter i-alkanes and olefins (H2S) and other gases from hydrocarbon streams; sulfur
generated as byproducts in FCC and other conversion pro- recovery from H2S separated in the acid gas removal unit;
cesses can be recovered to contribute to high-octane number and wastewater treatment. With the increasingly heavy and
streams (as alkylate and polymerate) to the gasoline pool. sour crudes being processed in refineries, the demand for
In contrast to the emphasis on gasoline production hydrogen and the need for removal and conversion of acid
and particularly on FCC in the U.S. refineries, European gases to elemental sulfur have become critically important
refineries as well as those in some other parts of the world for refinery operation. Supporting processes also include
mainly focus on diesel fuel production because of the the production of oxygenated hydrocarbons (e.g., ethyl
increasing proportion of diesel cars and the prominent tertiary butyl ether), particularly in Europe, which are
mass transport systems in these countries that rely on used as gasoline additives to increase the octane number
diesel fuel. Therefore, challenges associated with the diesel and control exhaust emissions. Benzene removal from
market requirements and the conversions of higher-boiling gasoline (to comply with environmental regulations) and
fractions of petroleum create higher interest in conversion the wastewater treatment units in refineries also constitute
processes such as mild hydrocracking, hydrocracking, and important supporting processes.
coking compared with that in U.S. refineries.
Catalytic hydrocracking combines hydrogenation and 5.4 Refinery Processes
cracking to handle feedstocks that are heavier than those 5.4.1 Separation Processes
that can be processed by FCC, such as heavy vacuum gas Separation processes constitute the initial stage of process-
oils and vacuum distillation residua (VDR), because of ing in a refinery and they prove a fractionation of products
excessive coke deposition on the catalyst in the absence of from conversion processes. Separation processes are
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hydrogen. Middle distillates (e.g., kerosene and diesel fuel) physical processes in which the chemical structure of the
are the principal products of hydrocracking. feedstocks does not change. Constituent compounds or
Thermal processes that do not use any catalysts, such groups of compounds are separated through processes such
as visbreaking and coking, are used to upgrade the VDR as desalting, distillation, stripping, gas absorption, solvent
to produce distillate fuels from the bottom of the barrel. extraction, and gas adsorption.
Visbreaking is a mild thermal cracking process with the
principal purpose of reducing the viscosity of VDR by slight 5.4.1.1 Desalting
carbon rejection in the visbreaking reactor to produce a Although distillation is usually referred to as the first process
heavy distillate or residual fuel oil. Lower yields of light in petroleum refineries, desalting takes place before distilla-
and middle distillates can also be produced by visbreaking tion. Salt dissolved in water to form brine enters the crude
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104 Petroleum Refining and Natural Gas Processing

stream as a contaminant during the production or transpor- tion of acid to recycled water. During the desalting process,
tation of oil to refineries. If salt is not removed from crude some other elements in crude such as V, Mg, and Fe can
oil, serious damage can result, especially in the heater tubes, also be reduced between 30 and 75 % whereas salt, Ca, and
because of corrosion caused by the presence of chloride. Salt Na can be reduced by 90 %. Therefore, the stages of the
in crude oil also causes a reduction in heat transfer rates in desalting process can be summarized as
heat exchangers and furnaces. Salt concentration in crude 1. Adding dilution (or less saline) water to crude,
oil is usually expressed in terms of pounds of equivalent 2. Mixing dilution water with crude by a mixer, and
sodium chloride per thousand barrels of clear (water-free) 3. Dehydration of crude to separate crude and the diluted
crude and is reported as lb/1000 bbl, or simply PTB. In the brine (salt and water) phase.
United States and Europe, desalting is done in the refineries Desalting can be performed in a single- or two-stage
to reduce the PTB of crude to 1. PTB can be calculated as [2] unit. The amount of water wash and the temperature of the
mixing process mainly depend on the crude API gravity, as
%S & W ppmw shown in Table 5.1.
PTB = 1000 (350SGbrine ) (5.1) The main parameters that should be considered before
100 − % S & W 106
the installation of a desalting unit are
• The number of desalting stages,
where: • The dehydration level achieved (vol % of salt and
%S&W = volume percentage of salt and water in oil water) remaining in the crude leaving the desalter,
[0.1→ 1], • The salinity of the brine remaining in the crude,
ppmw = salt content of water in ppmw, and • The efficiency of the mixing of dilution water and crude,
SGbrine = specific gravity of brine (>1), which depends • The salinity of dilution water, and
on the salt concentration of water. • The required PTB specification.
For example, seawater with salinity of 35,000 ppmw (or As a rule of thumb, if the required PTB is 20–50, then
3.5 wt %) has a specific gravity of 1.02 [1]. The relation seawater may be used as dilution water. The number of
between specific gravity of brine and its salt content can stages depends on the level of dehydration in the remaining
be expressed as SGbrine = 1 + 6.7 ⋅ 10–7(ppmw) or SGbrine = 1 + crude [2]:
0.0067(S%), in which S% is the salt content (total dissolved • Single-stage: 5–7 vol % (salt and water) remaining in crude,
solid) of brine in percentage weight. • Two-stage: 1–2 vol % (salt and water) remaining in crude,
Processes that reduce the PTB of a crude to 1 may include • Three-stage: Used for desalting heavy and viscous
• Adding demulsifier (soaps, sulfonates), crudes (API gravity of 10–20).
• A wetting agent for solid removal, The design calculations related to the level of dehydration
• Heating to 200–300°F, and and desalting in a desalter are based on material balances
• Electrostatic coalescence. for the salt and water.
Desalting in refineries is more economical than in the
field because heat is readily available from the refinery 5.4.1.2 Distillation
flue gases. General methods of desalting are shown in In this section, the principles of distillation and various
Figure 5.2 as modified from Manning [2]. By adding hot methods are introduced, followed by a description of distil-
water to crude, salt associated with brine in the crude is dis- lation towers in refineries, straight-run products, and the
solved in the hot water and then the same amount of water intermediate streams obtained from distillation processes.
is removed as brine. In this way, the salt concentration of
brine associated with the crude is decreased although the 5.4.1.2.1 Operation and Types of Distillation Processes
percentage volume of brine may remain the same as before Distillation is the main physical process in refineries that
the desalting process. The efficiency of a desalting process separates hydrocarbon compounds into distillate fractions
largely depends on the level of mixing of the added hot on the basis of their boiling points or volatility [3–5]. More
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water with the crude and the separation of brine. One of the volatile compounds (with low boiling points) tend to vapor-
most effective means of this process is mixing/coalescing ize more quickly than heavy compounds, and this forms
using high voltage. By creating a voltage of approximately the basis of separation through distillation. In a distillation
30,000–40,000 V within 1–2 s, small particles are formed column, light components appear in the top as top product
that make mixing very effective. After just 1 s of application, and the heavier part of the mixture appears in the bottom.
the voltage is reduced to 0 (i.e., within 3–4 s) for reagglom- For a crude that is a mixture of hundreds of hydrocarbons,
eration of the small particles to form larger units (coalescing some very light compounds such as ethane and propane
process) and enhance the separation of brine from oil. This only appear in the top whereas extremely heavy and nonvola-
cycle is repeated until the desired level of separation is tile compounds such as asphalts only appear in the bottom.
obtained. The desalter unit is simply an electrostatic heat The condensed top product is also referred to as “distillate,”
treater to separate crude from the dilution water through or overhead product.
extensive subdivision and better exchange of salt between Figure 5.3 shows a flow diagram for a typical crude
the oil and dilution water. As the electric field is reduced, distillation unit (CDU) [6]. The CDU consumes a significant
large water droplets are formed and settle down accord- fraction of the energy consumed in a refinery, and, as shown
ing to Stokes law. By use of electrostatic coalescence, the in Figure 5.3, it has a complex heat exchanger network
%S&W of crude can be reduced to 0.1–0.15 (in vol %) (HEN) for energy economy. The HEN consists of several heat
whereas without an electric field it can only be reduced to exchangers in series or parallel configurations to extract
0.5–1 % [2]. Dehydration of crude is best obtained at a pH energy from the distillation column pumparounds or side
of 6. However, the pH should never exceed 8 because of streams. The crude is heated at three stages before entering
emulsion
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Chapter 5 n Crude Oil Refining Processes 105

(a)

(b)

(c)

Figure 5.2—Three general methods for the desalting of crude oil based on three oil/water separation methods: (a) settling,
(b) use of an electric field, and (c) use of a packed column. Source: Figure modified from [2].

preflash column) may be included in the crude preheater

Table 5.1—Amount of Water Wash and train. This preflash step separates volatile fractions such
Temperature vs. Crude Gravity [2] fuel gas, LPG, and light naphtha to reduce the quantity of
°API Water Wash (vol %) Temperature (°C (°F)) feed into the furnace. The separation of the light fractions
before the furnace allows a better separation of the products
API > 40 3–4 115–125 (240–260)
in the distillation column and conserves energy. The crude
30 < API < 40 4–7 125–140 (260–280) preheat train is one of the most complex units that need to
be controlled effectively for an optimal energy balance for
API < 30 7–10 140–150 (280–300)
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the CDU that is important for the refinery’s energy economy.
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106 Petroleum Refining and Natural Gas Processing

Figure 5.3—A crude distillation unit (CDU) and its HEN [6]. Source: Figure used with permission.

Siemanond and Kosol [6] have studied the energy

requirements for a light (Arabian) and a heavy (Bacha
Table 5.3—Heat Exchanger Duties for
quero) crude. The yields of distillate products from these
Distillation of Two Crudes [6]
crudes are given in Table 5.2, indicating larger distillate Energy Consumption of CDU (106 W)
yields and lower residue yield from the Arabian light. Table 5.3
Light Crude Heavy Crude
gives the heat exchanger and condenser duties for the distil- Feed at Feed at
lation of two crudes for which the temperature of the crude Utility 5000 bbl/h 5000 bbl/h
and distillation products is set at 30ºC. It should be noted
that most of the energy necessary for distillation is added in Steam and steam duty 7.67 8.07
the external furnace, as can be seen in Table 5.3. The total Condenser duty 62.3 13.9
energy required for distillation includes the energy needed
to evaporate the side stream products and a small amount
needed to provide internal reflux that is called “overflash.” The performance of a CDU can be significantly improved
Keeping the amount of overflash to a minimum is also if part of the top liquid product after the condenser is
important for the energy economy in the CDU. returned into the distillation column as reflux. The contact
between the upward vapor phase and the downward liquid
phase (as a result of reflux) would increase the exchange
of components between the two phases. Light components
Table 5.2—Products from a Light and Heavy
evaporate from the liquid phase, and heavy components
Crude Obtained from a CDU [6]
condense from the vapor phase into the liquid phase to
Product Products from Products from improve the fractionation in the distillation column.
Boiling Light Crude at Heavy Crude at The distillation columns work as a multistage distillation
Products Range (°C) 30°C (vol %) 30°C (vol %) system in which each stage is equivalent to a single distil-
Naphtha 0–171 23 6 lation unit. To have a good separation, vapor and liquid
leaving each stage should reach vapor/liquid equilibrium.
Kerosene 171–271 18 10 Temperature along the column increases from the top to
Gas oil 271–473 28 22 the bottom, and the crude oil enters on the feed tray. The
section above the feed tray is known as the rectification
Residue >473 31 62
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and below the feed is referred to as the stripping section.
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Chapter 5 n Crude Oil Refining Processes 107

To have better vaporization and separation of the heavier mainly due to the low relative volatility of components
components, steam is typically injected into the column that requires a larger number of trays for a desired level of
at the bottom. The presence of steam decreases the partial separation. Heavy residues distilled in a vacuum tower have
pressure of hydrocarbons, and they can be vaporized at high molar volumes; therefore, the diameter of vacuum
lower temperatures. Distillation at lower temperatures is towers is much larger than those of atmospheric towers.
desirable because high temperatures could lead to the The vacuum tower’s diameter could be as large as 40 ft
degradation of thermally labile compounds. depending on the feed rate.
The top condenser of the distillation column can be a
partial condenser to obtain a liquid stream for the reflux, 5.4.1.2.2 Straight-Run Products and Intermediate
and the product is condensed in a second condenser. The Streams from Distillation
bottom liquid is also partially vaporized in a reboiler, and The distillation of crude oil in the atmospheric distillation
a further fractionation can occur in the reboiler because column gives fractions that include straight-run products,
it acts like a separation stage. The heat required in the such as LPG, naphtha, kerosene, and light and heavy gas
reboiler is provided by high-pressure steam. The reboiler oils [7,8]. The vacuum column generates intermediate
drives the operation of a distillation column as it generates streams (i.e., light and heavy vacuum gas oils and vacuum
vapor that flows upward in the column. Having a higher residue) that are subjected to subsequent processing to pro-
reflux rate can increase the purity of the top products; duce light and middle distillate fuels and nonfuel products.
however, it reduces the production and requires the addition The specifications of all fuels and materials obtained from
of more energy in the reboiler. Therefore, an optimal value of crude oil are presented in Chapters 2 and 4.
the reflux can be determined through column optimization As seen in Figure 5.3, the vapors from the top of the
and minimizing the total column cost as will be discussed atmospheric column (overhead products) are condensed and
in Chapter 13. Distillation columns can be tray or packed separated into gas and liquid streams in the accumulator.
columns. Details of different column types and their advan- The gas is further separated into fuel gas (methane and
tages are discussed in Chapter 13. ethane) that is burned for generating heat or steam in the
A form of single-stage separation is called flash distilla- refinery as well as LPG. LPG that consists of propane and
tion or simply flash, in which the temperature and pressure butane is the lightest straight-run product from crude oil
in the unit are controlled in a way that only a part of the distillation. LPG may need to be treated to remove impurities
liquid feed is vaporized. The vapor product from the flash such as H2S, elemental sulfur, and carbonyl sulfide (COS).
can be condensed for recovery. Liquid feed can be partially Part of the liquid overhead product (full-range naphtha)
vaporized either by heating at constant pressure (similar to is returned to the column as reflux. The rest of the overhead
what happens in a reboiler) or by reducing the pressure at liquid is separated into light and heavy naphtha. Light
constant temperature. The vapor and liquid streams leaving a naphtha can be used as specialty solvent, after purification,
flash chamber approach equilibrium if the flash unit oper- if necessary, or sent to an isomerization unit to increase its
ates close to an ideal stage. Such flash units are common in octane number to become a blending component for gaso-
refineries where the light gases are flashed out from a liquid line. Heavy naphtha is hydrotreated and usually directed to
by reducing the pressure. a catalytic reforming unit to produce high-octane gasoline,
In a refinery, desalted crude oil usually enters the as shown in Figure 5.1 and discussed in more detail in
atmospheric distillation column after going through a Section 5.4.2.1.2. Condensed water is sent to a water treat-
preflash drum or column, as described above. Because crude ment plant.
oil is a mixture of thousands of different compounds, the The side streams are separated in the side cut steam
fractional distillation products also contain many different strippers into middle distillates (i.e., kerosene) and light and
compounds, particularly in fractions with higher boiling heavy gas oils. Kerosene is hydrotreated to produce jet fuel,
points. For every side stream product, five to eight trays are or to be used as a blending component for diesel fuel, or as
generally needed. There are also several plates below the a solvent. Light gas oil (LGO) is hydrotreated to produce
feed tray. For example, for a column with 4 side streams diesel fuel, and heavy gas oil (HGO) is hydrotreated to
there may be 25–30 trays. produce a blending component for diesel fuel or light fuel
The residue from an atmospheric distillation column oil. In refineries that are focused on maximizing gasoline
typically has an initial boiling point of approximately 650ºF production, atmospheric gas oils as well as vacuum gas oils
(~350ºC). Higher temperatures are not desirable in crude are used as feedstocks for FCC to produce more gasoline as
distillation because thermal cracking of some constituent the primary product, as discussed later in Section 5.4.2.1.1.
compounds may occur. To avoid thermal cracking in a Atmospheric residue is fed into the vacuum distillation
distillation column, heavy residue from the atmospheric column to be fractionated into light and heavy vacuum gas
tower is further distilled in a vacuum tower. After desalt- oil (LVGO and HVGO, respectively) and vacuum residue
ing, the crude is typically heated up to 550°F by a heat (VR). LVGO can be used for producing lubricating oil
exchanger and then to 750°F in a furnace. The temperature basestock after dewaxing to control the freezing point of the
of the bottom product of the atmospheric tower is raised to basestock. HVGO can be introduced to catalytic cracking
850°F before entering vacuum distillation. The pressure in or hydrocracking to produce light and middle distillates.
vacuum towers ranges from 10 to 50 mmHg. Finally, the bottom of the barrel, VR, can be used as feed-
The diameter of a typical atmospheric crude tower is stock for deasphalting to produce deasphalted oil (DAO)
approximately 13 ft, and the height is approximately 85 ft, and asphalt, for visbreaking to produce fuel oil, or coked
but towers for the fractional distillation of side products to produce light and middle distillates and petroleum coke.
such as LPGs could have diameters of 2–3 ft and be up In turn, DAO may be used as feedstock for dewaxing and
to 200 ft in height with as many as 30–100 trays. This is lubricating oil basestock production or as feedstock for
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108 Petroleum Refining and Natural Gas Processing

hydrocracking to produce primarily middle distillates (i.e., jet will then separate into two phases, A and B and A and C.
fuel and diesel fuel). The phase rich in solvent C (in this example ether is the
The role of distillation has remained significant in the rich phase) is called the “extract” whereas the phase rich in
historical evolution of refinery schemes that have been component B (water layer phase in this example) is called
referred to in the literature as follows: the “raffinate.” The extract phase then can be sent to a dis-
• Topping: Simple distillation only, not currently used. tillation column to separate A and C. In this way, one can
• Hydroskimming: Distillation combined with hydrotreat- separate component A from B and recover the solvent C for
ing, still used in some refineries. recycling. In an ideal separation, the two phases of extract
• Conversion: Including vacuum distillation with the and raffinate are in equilibrium and principles of liquid-
chemical conversion of vacuum distillates into light liquid equilibrium will be used for the design and operation
products. of the extractor. A multistage countercurrent extraction
• Deep conversion: Chemical conversion of VDR into unit is commonly used in the form of a column to sepa-
light products. rate two miscible liquids to a certain degree of purity. In
• Lubricant production: Special vacuum distillation incor- the process, the heavy liquid usually enters from top of
porated with deasphalting, lubricating oil extraction, the column whereas light liquid (usually solvent phase)
dewaxing, and finishing. enters countercurrently from the bottom. The number of
stages or trays necessary for the desired separation in such
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5.4.1.3 Other Separation Processes: columns can be determined through equilibrium data and
Absorption, Stripping, Extraction, and the operating line. As an example, liquid-liquid extraction
Adsorption separates aromatics from aliphatic hydrocarbon mixtures
There are several other physical separation processes that by using a mixture of diethylene glycol (90–92 %) and
are used in refineries to separate components from each water (8–10 %). Aromatics such as benzene, toluene, and
other in liquid and gas phases. Absorption is a process in xylene(s) can be separated from oil by use of sulfolane in
which a gas component is separated using an amine sol- a liquid-liquid extraction process [1]. The design of such
vent in an absorption column. Stripping is the opposite of units is discussed in Chapter 13.
absorption and occurs when a volatile component is evapo- Another physical separation process used in refineries
rated from a liquid phase into a gas phase. This process is is adsorption, in which usually a gas is separated from a gas
usually used to recover enriched solvent from an absorption mixture by a solid phase called the adsorbent. This process
column as will be discussed in Chapter 13. can also be used for adsorption of a component in liquid
An absorption column is similar to a distillation column mixtures such as removal of hydrocarbons from water.
(tray or packed) in which good contact between gas and Adsorption is a useful process when a component exists in
liquid streams is needed to have good performance in the small quantities. For example after separation of H2S from
column. However, absorption columns do not have a con- natural gas through a gas absorption process, the remaining
denser or a reboiler. Rich gas enters from the bottom and amount of H2S in the gas mixture can be removed through
solvent enters from the top, whereas rich solvent leaves an adsorption process yielding a gas with a very low
the column through the bottom. Absorption columns usu- concentration of H2S. This process is also quite useful to
ally operate at low temperatures but high pressures. Good remove odors and pollutants from air.
absorption solvents should be nontoxic, cheap, nonvolatile, The effectiveness of an adsorption process largely
and possess a high absorption capacity. In general, the depends on the characteristics and types of adsorbents (the
phrase “like dissolves like” works for absorption as well. For solid phase). The adsorbents are typically in the form of
example, to separate C3 and C4 from a gas mixture of C1, C2, small beads or pellets ranging from 0.1 to 12 mm in size,
C3, and C4, a hydrocarbon solvent such as a paraffinic oil with the larger particle being used in packed beds. Columns
would be suitable. A heavier component (e.g., C4) tends to are filled with adsorbent beads and gas feed enters from the
be absorbed more than C3 and the other light components bottom of the column. The porosity of particles is approxi-
because C4 is closer in structure to that of a paraffinic sol- mately 50 %, and the adsorption usually occurs as a
vent such as decane. The absorption capacity of a solvent monolayer on the surface of a solid. When gas is introduced
increases for a given compound that has similar chemical into a solid bed column, it first diffuses into the bulk of the
and physical properties to those of the solvent. gas phase and then through pores of the solid before reach-
Another physical separation process is solvent extraction, ing the solid surface. The overall performance also depends
in which a component is separated from a liquid mixture on the diffusion rates in the gas and solid pores as well as
using a liquid solvent. A separation of two components, A the kinetics of the adsorption process. Good adsorbents
and B, by distillation is possible when the difference between have a high surface area up to 2000 m2/g whereas a value of
vapor pressure (or boiling points) of the components is large 1200 m2/g is considered a good surface area. Various kinds
(high relative volatility). However, if the boiling points of of adsorbents in the order of surface area include activated
the components are close to each other, the separation by carbon, silica gel, activated alumina, molecular sieve zeo-
distillation requires a large column with a high cost. If the lites, and synthetic polymers and resins in which activated
boiling points of two components are the same (i.e., relative carbons usually have surface areas of 300–1200 m2/g and
volatility of unity), then separation by distillation is not alumina has a surface area of 200–500 m2/g [3].
possible, and an alternative technique is needed. Consider
a solution of acetic acid (component A) in water (compo- 5.4.1.4 Dewaxing and Lubricating Oil
nent B). Solvent isopropyl ether (component C) is added Production
in which C is partially soluble with component A but not Dewaxing processes are designed to remove wax from
soluble in B. The three-component mixture of A, B, and C precursor lubricating oils (LVGOs or DAOs) to give the
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Chapter 5 n Crude Oil Refining Processes 109

lubricating oil basestock good fluidity characteristics at low 5.4.1.5 Deasphalting: Asphalt and DAO
temperatures. An oil can generally be dewaxed by separation Production
of wax as a solid that crystallizes from the oils at low Asphaltenes, as discussed in Chapter 2, consist of a
temperatures in a process called “solvent dewaxing.” high-molecular-weight aromatic hydrocarbon containing
Before the 1930s, naphthenic and paraffinic oils were heteroatoms such as sulfur and nitrogen. Asphaltenes
used as lubricants for motors, and both were solvent (i.e., are associated with heavy residues from a vacuum tower
phenol) extracted to improve their quality [1]. However, and can be separated from the residue through a solvent
lubricating oils are mainly composed of normal and separation process. As much as 80 % of the residue from
branched paraffins. Lubricating oils were produced in early vacuum crude oil towers is paraffinic material that can be
refineries as byproducts of paraffin wax. Lubricating oil upgraded to diesel fuel. Low-molecular-weight paraffins such
typically has high boiling points (>400°C) and high viscosity. as propane, butane, or pentane can be added to asphaltenic
The carbon number range for lubricating oil is usually oils, and asphaltenes are separated as solid asphalt. The
between 25 and 35–40 [1]. Lubricating oil can be produced mechanism of separation is through the density difference
in four steps: between asphaltenes and the oil/solvent solution. Undesir-
1. Distillation to remove lighter components, able heteroatoms such as sulfur, nitrogen, and metals are
2. Solvent refining or hydrogen treatment to remove non- also removed through deasphalting of oil. Deasphalting is
hydrocarbon compounds, usually applied to vacuum gas oil, feedstocks for lubricat-
3. Dewaxing to remove wax constituents and to improve ing basestocks, and distillation. Upgrading of heavy oils
low-temperature properties, and through deasphalting can be done at the production site
4. Clay treatment (or hydrogen treatment) to prevent of an oil field, which results in better quality crude for
instability of the product [1]. export and processing, as discussed in Chapter 8. Removal
SAE has classified lubricating oils into different classes of asphaltene through solvent extraction is common in
on the basis of their kinematic viscosity. For example, the refineries to remove asphaltene from heavy residues and
viscosity of grade SAE 20 oil should have a minimum value asphaltenic oils. LPG can be used to precipitate asphaltic
of 5.6 cSt and a maximum value of 9.3 cSt at 100°C (212°F). materials. When propane is added to oil containing asphal-
The solvents used in the solvent dewaxing of oils are tene, propane dissolves in oil, but it rejects asphaltene because
naphtha, propane, sulfur dioxide, acetone-benzene, methyl of a considerable difference in their chemical structure
ethyl ketone-benzene (benzol), and methyl-n-propyl ketone. and molar size. Propane can then be recovered through
Currently, ketone solvents are commonly used in dewaxing an evaporation process as shown in Figure 5.5 [1]. In this
processing. Processes of dewaxing include contacting the process, the heavy feedstock and 3–10 times its volume of
feedstock with the solvent, precipitating the wax from the liquefied propane are pumped together through a mixing
mixture by chilling, and recovering the solvent from the wax device and then into a settling tank. The temperature is
and dewaxed oil for recycling. Recent dewaxing processes maintained between 27 and 71°C, in which the higher the
include catalytic dewaxing, which is a mild hydrocracking temperature, the greater the tendency of asphaltic materials
process and is conducted at temperatures in the range of to separate. However, the temperature should be above the
280–400°C and pressures in the range of 300–1500 psi, asphaltene pumping temperature, and the propane is main-
depending on the type of feedstock used and the product tained in the liquid state by a pressure of approximately
required. The catalyst used for the process is the ZSM-5 200 psi. The final products of the deasphalting process are
catalyst (MFI according to the IUPAC Framework Type asphalt and DAO, as shown in Figure 5.5. Other methods of
Code). This catalyst is selective for n-paraffin cracking deasphalting are discussed by Speight [1]. Another process
through molecular sieving. A catalytic dewaxing process is proposed by Honeywell’s UOP and is shown in Figure 5.6
developed by Mobil is shown in Figure 5.4. [9]. The UOP deasphalting process produces DAO that is
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Figure 5.4—Catalytic dewaxing process that is based on the Mobil process as given in [1].
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110 Petroleum Refining and Natural Gas Processing

Figure 5.5—Schematic of deasphalting process by propane that is based on the method recommended in [1].

Figure 5.6—UOP/FWUSA solvent deasphalting process [9]. Source: Figure used with permission from UOP LLC, a Honeywell
company.

rich in paraffinic-type molecules that can later be converted but its quality declines. As the DAO yield increases, the
in an FCC unit or hydrocracking unit. The pitch product concentration of contaminants in the DAO also increases.
contains most of the residue’s contaminants (metals, Changing solvents is not usually considered as a day-to-day
asphaltenes, Conradson carbon) and is rich in aromatic operating practice [9].
compounds and asphaltenes. The feed (normally VR) is
mixed with a light paraffinic solvent, typically butane, 5.4.2 Conversion Processes
where the DAO is solubilized in the solvent. The insoluble Conversion processes change the molecular structure of
part will precipitate out of the mixed solution (Figure 5.6). the crude oil fractions from distillation processes and
The solvent can be recovered and recycled back to the other intermediate products from different refinery units
beginning of the process. Considering the solvent selec- to increase the quantity and quality of premium distillate
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tion, as the solvent gets heavier, the yield of DAO increases, fuels such as gasoline, jet fuel, diesel fuel, and fuel oils. This
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Chapter 5 n Crude Oil Refining Processes 111

subsection covers the principal conversion processes used the crackate (cracked gasoline with high octane number),
in a refinery that are grouped on the basis of the targeted light olefins, cycle oils, and slurry oil that are sent to the
distillate fuel product starting with gasoline production. fractionator. A carbon-rich byproduct of catalytic cracking,
termed “coke,” deposits on catalyst surfaces and blocks the
5.4.2.1 Gasoline Production active sites. The coked catalysts are sent to the regenerator
Gasoline is the principal product in U.S. refineries, account- unit to burn off the coke deposit, and the regenerated cata-
ing for 40 % by volume of all refinery products [10] because lysts are returned to the reactor to complete the catalyst
of the high demand for motor gasoline as the primary fuel cycle. The heat necessary for the endothermic cracking
for automobiles. Properties and specifications of gasoline reactions can thus be supplied by the hot catalyst particles
products are discussed in Chapters 2 and 4. Among all of that are heated by burning the coke deposit off their
the processes used for producing gasoline, the process of surface. For most FCC units, there exists a good heat bal-
FCC accounts for the largest volume of gasoline production ance between the reactor and the regenerator for effective
through the cracking of gas oils. Catalytic reforming and thermal integration. FCC is considered a carbon rejection
isomerization processes are performed to increase the process because the coke deposited on the catalyst surface
octane number of heavy naphtha and light naphtha fractions, and eventually burned off for heat is rich in carbon and
respectively, without a major change in molecular weight or thus enables the production of large quantities of a light
boiling point range of the feedstocks to provide high-octane distillate (crackate) in the process.
number gasoline streams to the blending pool. On the other Two different configurations of the FCC process exist
hand, alkylation and polymerization are used to combine depending on the positions of the reactor and the regenera-
lighter hydrocarbons (C3 and C4 alkanes and olefins) gen- tor: they can be side by side or stacked, where the reactor
erated in conversion processes (e.g., FCC and coking) to is mounted on top of the regenerator. Major licensor compa-
produce branched alkanes and olefins (i-C7-i-C8) with high nies that offer FCC processes with different configurations
octane numbers for the gasoline pool. These processes include Kellogg Brown & Root, CB&I Lummus, ExxonMobil
are introduced in more detail in the following sections. It Research and Engineering, Shell Global Solutions Interna-
should be noted that there are other refining processes that tional, Stone & Webster Engineering Corporation, Institut
produce gasoline blending streams as byproducts, as will be Francais du Petrole (IFP), and UOP.
pointed out when discussing these processes. The flow diagram of a UOP FCC process is shown
in Figure 5.7 [11]. The gas oil feed mixed with steam is
5.4.2.1.1 FCC introduced to the bottom of the riser (reactor) with the hot
The FCC process is the most widely used refinery process catalyst particles from the regenerator. Most of the cracking
to produce high-octane gasoline mainly from straight-run reactions take place in the riser. After steam stripping in
atmospheric gas oil and LVGO. This process involves the upper part of the reactor, the coked catalysts are sent
breaking up long chains of n-alkanes into shorter chains of to the regenerator and the products are directed to the
branched alkanes (isoalkanes), cycloalkanes (naphthenes), fractionator section that consists of a main column and a
and aromatics by using acidic catalysts. In addition to gas concentration (separation) unit. UOP engineers are also
high-octane gasoline, FCC produces LPG, cycle oils, and proposing two-stage regenerator units for FCC plants. The
olefin-rich light hydrocarbons (C3, C4) that can be used in advantages of a two-stage regenerator over a single-stage
alkylation and polymerization reactions to produce higher regenerator are
molecular weight branched alkanes and olefins to contribute • Easier to operate,
to the blending pool of high-octane gasoline in refineries. • Uniform coke burn,
Because of the central importance of FCC in petroleum • Low carbon residue (<0.05 wt %),
refining, a separate chapter (Chapter 6) is devoted to discuss- • Higher conversion of carbon monoxide (CO) to carbon
ing this process in detail. Only a brief description of the dioxide (CO2),
process is presented here. • Lower nitrogen oxide (NOx) emissions, and
Increasing demand for gasoline along with the need • Minimizing catalyst deactivation.
to produce high-octane gasoline for increasingly more Addition of a third-stage catalyst regenerator may con-
powerful spark ignition engines led to the development trol the emission of particulate matter (PM) in flue gases.
and maturation of catalytic cracking processes just before It could reduce the PM to meet the 50-mg/Nm3 clean gas
and during World War II. After the development of a fixed- requirement, help axial flow separation, and reduce PM to
bed (Houdry process, 1936) and a moving-bed (Thermofor less than 0.8 lbPM/1000 lb (coke).
Catalytic Cracking, 1941) catalytic cracking process, fluid-bed Another modification to FCC plants could be installa-
catalytic cracking (FCC, 1942) became the most widely tion of a catalyst cooler, which may provide better control
used process worldwide because of the improved thermal of the catalyst/oil ratio; the ability to optimize the FCC
efficiency of the process and the high product selectivity operating conditions, increase conversions, and process
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achieved, particularly after the introduction of crystalline heavier residual feedstocks; and better catalyst activity and
zeolites as catalysts in the 1960s. catalyst maintenance. Recent advancements in FCC pro-
In general terms, the FCC process can be divided into cesses are discussed in Chapters 6 and 7.
three components: the reactor, the catalyst regenerator,
and the product fractionator. In the reactor, the cracking 5.4.2.1.2 Catalytic Reforming
reactions initiate on the active sites of the catalysts with the Catalytic reforming converts low-octane straight-run naphtha
formation of carbocations (positively charged hydrocarbon fractions (particularly heavy naphtha that is rich in naph-
ions), and the subsequent ionic chain reactions produce thenes) into a high-octane, low-sulfur reformate, which is
branched alkanes and aromatic compounds to constitute a major blending product for gasoline. The most valuable
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112 Petroleum Refining and Natural Gas Processing

Figure 5.7—A UOP FCC process flow diagram [11]. Source: Figure used with permission from UOP LLC, a Honeywell company.

byproduct from catalytic reforming is the hydrogen needed “semiregenerative catalytic reformers,” need to be shut
in a refinery with the increasing demand for hydrotreating down once every 6–24 months for the in situ regeneration
and hydrocracking processes. Most reforming catalysts of catalysts that are deactivated by coke deposition. Later
contain platinum supported on alumina, and some may designs included an extra reactor (a swing reactor) to
contain additional metals such as rhenium and tin in bi- or enable isolation of one reactor at a time to undergo catalyst
trimetallic catalyst formulations. In most cases, the naphtha regeneration whereas the other three reactors are running.
feedstock needs to be hydrotreated before reforming to This configuration enables longer on-stream times (up to
protect the platinum catalyst from poisoning by sulfur or 5 years) before scheduled shutdowns for catalyst regen-
nitrogen species. With the more stringent requirements on eration, but it has not become popular.
benzene and the total aromatics limit in the United States A continuous catalyst regeneration (CCR) scheme for
and Europe, the amount of reformate that can be used in reforming came on stream in 1971. Figure 5.8 shows a flow
gasoline blending has been limited, but the function of diagram for the UOP CCR Platforming process [12]. The
catalytic reforming as the only internal source of hydrogen reactors are stacked with a moving bed of catalyst trickling
continues to be important for refineries. from the top reactor to the bottom reactor by gravity. Partially
The first commercial catalytic reforming process was deactivated catalyst from the bottom of the reactor stack is
introduced by UOP in 1949 as the PlatformingTM process continuously withdrawn and transferred to the CCR regen-
that used three fixed-bed reactors. The reactors operate in erator. The regenerated catalyst is reinjected to the top of
series with furnaces placed before each reactor to heat the the first reactor to complete the catalyst circulation cycle.
feedstock and the reactor effluents to 500–530°C before Hydrotreated naphtha feed is combined with recycle
entering each reactor because the predominant reform- hydrogen gas and heat exchanged with the reactor effluent.
ing reactions are highly endothermic. These units, called The combined feed is then raised to reaction temperature

Figure 5.8—UOP CCR Platforming process [12]. Source: Figure used with permission from UOP LLC, a Honeywell company.
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Chapter 5 n Crude Oil Refining Processes 113

in the charge heater and sent to the first reactor section. Reactions 1–3. However, it is necessary to maintain a
Because the predominant reforming reactions are endo- sufficiently high hydrogen pressure in the reactors to inhibit
thermic, an inter-reactor heater is used to reheat the charge coke deposition. Hydrocracking is an undesired side reac-
to reaction temperature before it is introduced to the next tion in catalytic reforming because it consumes hydrogen
reactor. The effluent from the last reactor is heat exchanged and decreases the reformate yield by producing gaseous
with the combined feed, cooled, and separated into vapor hydrocarbons. Hydrocracking reactions are exothermic,
and liquid products in a separator. The vapor phase is rich but they can still be favored at high temperatures because of
in hydrogen gas, and a portion of the gas is compressed and kinetics and favored obviously by high hydrogen pressures.
recycled back to the reactors. Recycling hydrogen is necessary Typically, reformers operate at pressures from 50 to 350 psig
to suppress coking on the catalysts. The hydrogen-rich gas is (345–2415 kPa), a hydrogen/feed ratio of 3–8 mol H2/mol
compressed and charged together with the separator liquid feed, and liquid hourly space velocities of 1–3 [13].
phase to the product recovery section. The performance of A reaction network for catalytic reforming is shown
the unit (i.e., steady reformate yield and quality) depends in Figure 5.10 [14], indicating the role of metallic (M) and
strongly on the ability of the CCR regenerator to completely acidic (A) sites on the support. The surfaces of metals (e.g., Pt)
regenerate the catalyst. catalyze dehydrogenation reactions, whereas the acid sites
In addition to UOP’s Platforming process, the major on the support (e.g., alumina) catalyze isomerization and
commercial catalytic reforming processes include Powerform- cracking reactions. Metal and acid sites are involved in the
ing™ (ExxonMobil), Ultraforming™ and Magnaforming™ catalysis of hydrocracking reactions. Achieving the princi-
(BP), Catalytic Reforming (Engelhard), Reforming (IFP), and pal objective of catalytic reforming—high yields and high
Rheniforming™ (Chevron). quality of reformate—can be achieved, to a large extent,
The principal reactions of interest in catalytic reforming, by controlling the activity of the catalysts and the balance
shown in Figure 5.9, are between acidic and metallic sites to increase the selectivity
• Dehydrogenation of naphthenes to aromatics, to desirable reactions.
• Dehydroisomerization of alkyl-C5-naphthenes,
• Dehydrocyclization of n-paraffins to aromatics, and 5.4.2.1.3 Alkylation and Polymerization
• Isomerization of n-alkanes to i-alkanes. The alkylation process combines light isoparaffins, most
All of these reactions significantly increase the octane commonly isobutene, with C3–C4 olefins to produce a mix-
number (research octane number [RON] from 75 to 110 ture of higher molecular weight isoparaffins (i.e., alkylate) as
in Reaction 1, from 91 through 83 [cyclohexane] to 100 in a high-octane number blending component for the gasoline
Reaction 2, from 0 to 110 in Reaction 3, and from –10 to 90 pool. Isobutane and C3–C4 olefins are produced as byproducts
in Reaction 4). Large quantities of H2 are produced in the from FCC and other catalytic and thermal conversion pro-
highly endothermic Reactions 1–3. High temperatures and cesses in a refinery. The alkylation process was developed
low hydrogen pressures strongly promote the conversion in the 1930s and 1940s to initially produce high-octane
aviation gasoline, but later it became important for produc-
ing motor gasoline because the spark ignition engines have
become more powerful with higher compression ratios that
require fuel with higher octane numbers. With the recent
restrictions on benzene and the total aromatic hydrocarbon
contents of gasoline by environmental regulations, alkylation
has gained favor as an octane number booster over catalytic
reforming. Alkylate does not contain any olefinic or aromatic
hydrocarbons.
Alkylation reactions are catalyzed by strong acids (i.e.,
sulfuric acid [H2SO4] and hydrofluoric acid [HF]) to take
place more selectively at low temperatures—40–70°F for
H2SO4 and 100°F for HF. By careful selection of the operat-
ing conditions, a high proportion of products can fall in the
gasoline boiling range with motor octane numbers (MONs)
of 88–94 and RONs of 94–99 [15]. Early commercial units
used H2SO4, but more recently HF alkylation has found
more common use in petroleum refineries. HF can be more
easily regenerated than H2SO4 in the alkylation process, and
HF alkylation is less sensitive to temperature than H2SO4
alkylation [15]. In both processes, the volume of acid used
is approximately equal to the volume of liquid hydrocarbon
feed. Important operating variables include acid strength,
reaction temperature, isobutane/olefin ratio, and olefin
space velocity. The reactions are run at sufficiently high
pressures to keep the hydrocarbons and the acid in the
liquid phase. Good mixing of acid with hydrocarbons is
essential for high conversions.
Some examples of desired alkylation reactions (combi-
Figure 5.9—Principal reactions in catalytic reforming.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- nation of isoparaffins with olefins) are given in Figure 5.11.
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114 Petroleum Refining and Natural Gas Processing

Figure 5.10—A reaction network for catalytic reforming [14]. Source: Figure used with permission from UOP LLC, a Honeywell
company.

HF- propane stripper, defluorinator, and potassium hydroxide

(KOH) treater before it is recovered. Recycled isobutane is
drawn from the side of the fractionator and returned to the
entrance of the reactor after it is mixed with the dried olefin
and isobutane feed. The n-butane product is taken from the
side of the fractionators as vapor, condensed and KOH-
treated before recovery. The alkylate product is obtained
from the bottom of the fractionator. The HF catalyst is
regenerated onsite in the regeneration section where heavy
oils (tars) are removed from the catalyst.
Transporting and working with concentrated acids
pose safety risks. In particular, HF tends to form a vapor
cloud that is difficult to disperse. As examples for recent
developments to mitigate the risks associated with using
HF, one could cite the Reduced Volatility Alkylation Process
Figure 5.11—Desirable alkylation reactions [15]. (ReVAP™) and the Inventory Management Process (IMP®)
[16]. The ReVAP process drastically reduces the volatility of
These reactions are believed to occur through ionic chain HF acid, and IMP allows safer transfer of the catalyst inven-
reactions initiated by donation of a proton from the acid tory to a dedicated receiver vessel. The major licensor of the
catalyst to an olefin to produce a carbocation that reacts HF alkylation processes is UOP, whereas ExxonMobil and
with isobutane to form a tert-butyl cation. Subsequent Stratford Engineering Corporation license H2SO4 alkylation
propagation reactions involve the reactions of a tert-butyl processes. A newly designed alkylation process by UOP uses
cation with olefins to form larger isoparaffin cations that a solid catalyst called Alkylene®. Advantages of this new
lead to final products through reactions with isobutane to process over traditional HF alkylation processes (liquid
form a new tert-butyl cation to sustain the chain reaction acid technology) include no acid transportation, no acid
[15]. The alkylation reaction is highly exothermic, and cooling spills, no corrosion, and reduced maintenance cost. Efforts
the reactor contents during alkylation is important. to develop alternative processes that use solid acid catalysts
Figure 5.12 shows a flow diagram for a UOP HF instead of concentrated HF and H2SO4 for alkylation are
alkylation process [16]. Olefin and isobutane feed streams discussed in Chapters 9 and 10.
are dried to remove water before they are mixed with the The polymerization process combines propenes and
isobutane recycle stream. The mixture is fed to the reactor, butenes to produce higher olefins with high-octane numbers
where it is highly dispersed into an incoming stream of acid (97 RON and 83 MON) for the gasoline pool. The polym-
catalyst. Conversion of reactants to high-quality alkylate erization process was used extensively in the 1930s and
takes place quickly, and the mixture flows up to the settling 1940s, but it was replaced to a large extent by the alkylation
zone. In the settler, the catalyst is separated out as a bottom process after World War II. It has gained favor after phasing
phase and flows, by gravity, through the catalyst cooler and out the addition of tetraethyl lead (TEL) to gasoline, and
returns to the reactor. The hydrocarbon phase from the the demand for unleaded gasoline has increased. Typical
settler, which contains propane, recycled isobutane, normal polymerization reactions are shown in Figure 5.13 [15].
butane, and alkylate, is charged to the main fractionator. The most commonly licensed polymerization process
High-purity propane is sent overhead to pass through the is the UOP polymerization process, which uses phosphoric
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`

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Chapter 5 n Crude Oil Refining Processes 115

Settler

Feed Driers

Iso-butane

Olefin Feed
Isothermal
Reactor

Main
Fractionator
Motor Fuel
Butane

KOH
Treater
HF
Stripper Propane

De-flourinator

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
and KOH Treater

Accumulator
Alkylate

Figure 5.12—UOP HF alkylation (Alkylplus® ) process [16]. Source: Figure used with permission from UOP LLC, a Honeywell
company.

Figure 5.13—Typical polymerization reactions [15].

acid as catalyst. IFP licenses a Dimersol® process that future challenges and opportunities. A brief description of
produces dimers from propene or butene using a homoge- the process is given here using the UOP Par-IsomTM process
neous aluminum alkyl catalyst. as an example.
Figure 5.14 shows a simple flow diagram of a UOP
5.4.2.1.4 Isomerization Par-Isom process [17]. Typical feed sources for this process
Isomerization processes have been used to isomerize include hydrotreated light straight-run naphtha, light natu-
n-butane to isobutane used in alkylation and C5 /C6 n-paraffins ral gasoline, or condensate. The fresh C5/C6 feed combined
in light naphtha to the corresponding isoparaffins to produce with make-up and recycled hydrogen is directed to a heat
high-octane number gasoline stocks after the adoption exchange for heating the reactants to reaction temperature.
of lead-free gasoline. Catalytic isomerization processes Hot oil or high-pressure steam can be used as the heat source
that use hydrogen have been developed to operate under in this exchanger. The heated feed is sent to the reactor. The
moderate conditions. Chapter 7 reviews the chemistry of reactor effluent is sent to a product separator and stabilizer
hydroisomerization and the development and evolution to separate H2 to be recycled, the isomerate product, and
of hydroisomerization catalysts as well as the associated off gas. Typical isomerate product (C5+) yields are 97 wt %
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116 Petroleum Refining and Natural Gas Processing

Figure 5.14—UOP Par-Isomer Process [17]. Source: Figure used with permission from UOP LLC, a Honeywell company.

of the fresh feed, and the product octane number ranges Hydrocracking processes most commonly include
from 81 to 87, depending on the flow configuration and two reaction stages: hydrotreating to remove heteroatom
feedstock properties. (S, N, O) species and hydrocracking to increase the H/C
ratio of the hydrocarbons in the feeds by hydrogenation and
5.4.2.2 Jet Fuel, Diesel, Fuel Oil, and Coke to decrease their molecular weight by cracking. As shown
Production in Figure 5.15 [19], the hydrotreating reactor packed with
Although gasoline production can be a primary focus of cobalt-molybdenum catalysts precedes the hydrocracking
crude oil refining, as in the United States, 40–50 % of the reactor typically packed with nickel-tungsten catalysts (for

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
crude oil refined goes into the production of other fuels hydrogenation) supported on alumina/silica (for cracking).
and nonfuel materials. Many countries rely on diesel fuel The products from the hydrocracker are sent to a fraction-
as the primary fuel for ground transportation, and, in ator to be separated into gas and light distillates (LPG and
general, marine transportation relies heavily on diesel naphtha), middle distillates (kerosene and diesel [or LGO]),
or heavier fuel oils. The demand for jet fuel as the gas and HGO. HGO may be recycled to the hydrocracker for
turbine fuel for jet aircraft has been steadily increasing. a deeper conversion into light and middle distillates or
Considering that the crude oil available for refining is to extinction, as desired. The reactions are performed at
getting heavier and more contaminated, processes to con- 300–400°C and 8–15 MPa of hydrogen pressure.
vert heavy fractions of crude oils or heavy oils into clean In a refinery, hydrocracking complements catalytic
distillate products have become important, as discussed cracking by taking on the more aromatic feedstocks that
in Chapter 8. A brief description of hydrocracking, vis- resist cracking, including the byproducts of FCC, such as
breaking, thermal cracking, and coking is given here light cycle oil (LCO). In the United States, hydrocracking of
because these processes are discussed in some detail in LCO (from FCC) provides a large proportion of the diesel
Chapters 8 and 9. fuel production because straight-run LGO is a preferred
stock for FCC to produce gasoline as the principal product.
5.4.2.2.1 Catalytic Hydrocracking The major licensors of hydrocracking processes include
Catalytic hydrocracking is one of the latest additions to Chevron, UOP, ExxonMobil Research and Engineering, BP,
petroleum refining processes, with the first modern com- Shell, and BASF-IFP.
mercial unit started up by Chevron in 1958. The interest Recent advances in hydrotreating/hydrocracking pro-
in hydrocracking has been attributed to the increasing cesses and the hydrotreating/hydrocracking catalysts for
demand for light and middle distillates, the availability processing the residual fractions of crude oils and heavy
of byproduct hydrogen in large quantities from catalytic oils, including bitumen conversion to synthetic crude oil,
reforming, and the environmental regulations limiting are discussed in Chapters 8–10.
sulfur and aromatic hydrocarbons in motor fuels [18]. The
advantages of hydrocracking include its ability to handle a 5.4.2.2.2 Visbreaking and Thermal Cracking
wide range of feedstocks that may be difficult to process by Thermal cracking is the first commercial conversion pro-
catalytic cracking and its flexibility in selectivity between cess developed in the early 1900s principally to produce
light and middle distillates. As a hydrogen-addition process, more motor gasoline from crude oils and produce high-
hydrocracking provides high yields of valuable distillates octane gasoline for aircraft use, initiating the evolution of
without producing low-grade byproducts (e.g., heavy oils, the petroleum refinery. With the advent of catalytic cracking
gas, or coke) as experienced in carbon rejection processes in the 1930s and 1940s and its capability to produce higher
such as coking. yields of gasoline with higher octane number, thermal
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Chapter 5 n Crude Oil Refining Processes 117

Figure 5.15—A two-stage UOP hydrocracking process [19]. Source: Figure used with permission from UOP LLC, a Honeywell
company.

cracking of gas oils has ceased to be an important process in removing the coke from the drums and problems with
for gasoline production in modern refineries. As opposed grinding, although shot coke has some niche applications
to ionic chain reactions controlling catalytic cracking, free such as in titanium dioxide (TiO2) production. Sponge coke
radical chain reactions govern the thermal cracking chemis used as solid fuel and manufacturing anodes for alumi-
istry that generates high yields of gas, particularly methane num production. Among the delayed coking products, needle
(CH4), ethane (C2H6), and ethylene (C2H4), and produces coke is a specialty coke produced mostly from coking the
straight-chain alkanes in liquid products with low octane FCC decant oil; its production is approximately 1 million t
numbers. Therefore, a principal application of the thermal almost exclusively in the United States, United Kingdom,
cracking of distillate fractions in current refineries is lim- and Japan.
ited to naphtha cracking for the purpose of producing C2H4 The major properties of the needle coke include
for the petrochemical industry. However, thermal cracking • A low coefficient of thermal expansion,
of residual fractions, particularly VDR, is still practiced in • A low puffing tendency during graphitization because
association with visbreaking and coking processes in the of lower nitrogen and sulfur contents, and
refineries. • High mechanical strength.
Visbreaking is a mild thermal cracking process applied The anode coke has limits on metal contaminants,
to reduce the viscosity of VDR to produce fuel oil and some requiring less than 500 ppm of Ni and V in the coke. The
light products to increase the distillate yield in a refinery. price of fuel coke depends on its carbon purity (S, N, and
Commercial visbreaking processes and their significance metal contaminants); however, the fuel coke is traded at a
in the overall refinery scheme are discussed in Chapter 8. price comparable to that of the coal.

5.4.2.2.3 Coking
Despite the development of catalytic cracking processes,
coking processes in particular, the delayed coking process
has survived as a popular refining process all over the world
to refine the heavy end of crudes or heavy oils through carbon
rejection as coke. Chapter 8 discusses coking technologies
and processes (including fluid coking and flexicoking) in
some detail. Here, a brief description of the delayed coking
process is given with focus on the properties and the appli-
cations of the coke products. The petroleum coke produced
through the delayed coking process has reached 100 million
t/year in the world, and 20 million t are calcined for use in
metallurgy for processing alumina and titania as well as
raw material in the carbon industry for producing graphite
electrodes for electric arc furnaces and nuclear graphite.
There are basically three kinds of coke produced by
delayed coking: high-density shot coke, porous sponge coke,
and needle coke. Figure 5.16 describes the appearances,
specifications, and applications of these cokes. The formation
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- Figure 5.16—Appearances, properties, and applications of
of shot coke is usually troublesome because of difficulties cokes produced from delayed coking of vacuum residue.
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118 Petroleum Refining and Natural Gas Processing

Producing a high-quality coke (e.g., anode coke from the of coke as fuel, aluminum anode, or steel electrode coke,
delayed coking process) as a byproduct adds to the benefit respectively.
of producing distillate liquid fuels from very heavy feed- Operational control factors in the delayed coker are
stocks. Therefore, the pretreatment of the feed to increase mainly drum pressure, recycle ratio, and heater outlet
the coke quality becomes feasible. temperature. Their effects are not so significant on the
Delayed coking can deal with the heavy feeds that properties of the products, although there are optimal con-
cannot be upgraded by other refining processes because of ditions that can be selected. The properties of the products
the high coking yield and high contamination with metals, depend strongly on the properties of the feedstocks.
sulfur, and nitrogen. However, the feeds are recently being For a better performance of delayed coking opera-
treated before delayed coking to obtain better performance tion and higher product values, several feed pretreatment
in the processes and higher quality products. The treatment options are available and practiced. These procedures are
must be well designed in terms of objectives and procedures summarized in Table 5.6. One extreme is to charge the
because the treatment itself must overcome the difficulties heaviest feed into the delayed coker. Other thermal or
as expected from the composition of the feed. The objec- catalytic processes can refine the light fraction. Another
tives of pretreatment are summarized in Table 5.4. extreme is to reject the particular fraction, often the heaviest
The variety of feeds for delayed coking is now expanded end, to improve the coke quality. SDA (solvent deasphalt-
because of the larger variety of crudes and products from a ing process) is proposed as an effective way to remove the
greater variety of processes in petroleum refining and pet- heaviest end (the metal and S compounds present in the feed)
rochemical processes. To keep the coking process feasible to improve the coke quality. This also improves the liquid
and to improve the products’ quantity and quality from product quality and makes the process easier to control.
the particular feed, the feed can be adjusted. The delayed The issue that needs to be addressed with this option is how
coker requires limited viscosity and coking reactivity of to use the separated asphaltene fraction.
the feed, which must pass rapidly through the heating tube The feed can also be catalytically or thermally treated
(preheated) without any coke deposit on the tube wall. The to obtain a better performance in terms of product
heating of the feed may lead to the phase separation of yield and quality. Blending feeds with particular additives
the heavy fractions because of the vaporization and thermal (e.g., aromatic and hydroaromatic compounds) could also
cracking of the particular fraction. The phase separation improve the process and the quality of products and pro-
may result in the deposition of coke precursors on the vide a better control of the coking process.
heater tube and heterogeneous coking in the coker drum. The refining of the coker feed includes removal of con-
Heterogeneous coking often leads to the considerable deg- taminants, conversion of the heavy fraction, aromatization/
radation of coke quality and causes the formation of shot/ condensation of light paraffinic fractions, and hydrogenation
ball coke in the bottom of the drum. Some feed produces of the aromatic fraction. Such refining reactions are com-
such coke in the whole zone of the drum. bined for better performance. Selective hydrogenation is a
The quality and quantity of the products are controlled
as desired by the refiners. Usually refiners want high yields
of the distillates such as coker gasoline and gas oil. A higher Table 5.5—Quality Factors for Cokes from
quality of distillates such as low sulfur content is also the Delayed Coking Process
desired. Low-grade coke obtained from a low-grade feed
Quality Factor Fuel Coke Electrode Quality
does not have much value; therefore, its yield is minimized
by design. However, a high-quality coke, such as premium Free carbon
needle coke, is highly desired and its yield is maximized. contaminants
Quality factors for delayed cokes are summarized in Ash and minerals
Table 5.5. These factors are defined by their application Metal Lower fuel Lower electrode
quality quality
Sulfur SOx Puffing
Nitrogen NOx Puffing
Table 5.4—The Objectives for Feed
Pretreatment in Delayed Coking Metal Metal deposition Contamination in
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

electric refining
Feed Properties Effects
Sulfur SOx Puffing
Fluidity No coking in the heater tubes
Liquid phase coking Nitrogen NOx Puffing
Non-fusible component Fluidity and coking properties Density Very strong coke Coke strength and
is not desirable density of carbon
Contamination Quality of distillate and coke
electrode
Coke yield or Distillate Yield Higher yields of desired
Porosity cracks and Large coke size
products
their distribution desired
Coke structure Density
Graphitization extent Steel production
Porosity
Optical texture Optical texture Aluminum
Graphitization isotropic, mosaic, production
needle Steel production
Coking reactivity of the feed Coking in the heater and coke
drum Thermal expansion Steel production
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Chapter 5 n Crude Oil Refining Processes 119

metals from 10 to 1000 ppm. Once crude is fractionated by

Table 5.6—Pretreatments of Feeds for distillation, the heteroatoms (particularly S, N, and metal
Delayed Coking compounds) are distributed in the products. Heteroatom
Procedure Objectives compounds are mainly associated with the higher boil-
ing fractions and the residues that are rich in aromatic
Fractionations
compounds. The presence of heteroatom compounds in
Heavy end cut (SDA is Uniform fluidity
typical.) petroleum products is undesirable because they reduce fuel
Light component cut Higher coke yield stability, contribute to the emission of pollutants, and dam-
Treatment of lower quality age engines. Heteroatom compounds in refinery streams
feed (e.g., basic nitrogen compounds, sulfur compounds, and
(reactor volume efficiency) metals) can deactivate catalysts and promote coke formation.
The light products such as LPG and naphthas have low
Blending with Coking control
Aromatic additive Solvent fraction to keep liquid concentrations of sulfur and require minimal treatment,
Hydroaromatic additive phase during the coking such as absorption in alkaline solvents (e.g., H2S or mercaptan
Hydrogen donative additive sulfur) or conversion of mercaptans to sulfides to eliminate
to induce and keep liquid odor. For example, the UOP Merox™ process is widely used
phase to remove H2S and mercaptan sulfur (Merox extraction)
or to convert mercaptan sulfur to less-objectionable disul-
Acidic treatment
Dealkylation Aromaticity enhancement to fides (Merox sweetening) [20]. The Merox process can be
Aromatization control coking reactivity used to treat liquids such as LPG, naphtha, and kerosene.
Removing sulfur from higher molecular weight and more
Hydrogenation Hydroaromatic feed controls complex molecules requires hydrotreatment processes that
coking reactivity to increase
use hydrogen. The advancement in hydrotreatment pro-
the distillate and coke quality
cesses to desulfurize higher boiling distillate fractions and
Hydrocracking Hydroaromatic feed controls FCC products are discussed in Chapters 9 and 10. A brief
coking reactivity to increase introduction to hydrotreatment processes is given later in
the distillate and coke quality this section.
Hydrorefining Particularly strict sulfur limits have recently been
HDM Metal reduction for coke imposed on diesel fuels so that the particulate emissions
HDS quality from diesel engines can be reduced. In the United States,
HDN Sulfur reduction for coke the government regulations [21] require that highway and
quality nonroad, locomotive, and marine engines that use diesel
Nitrogen reduction for coke fuel meet a maximum specification of 15 ppm sulfur by
quality 2014 with a full compliance for highway use and nonroad
diesel fuel since December 2010. It also requires full com-
pliance for locomotive and marine diesel fuel use by 2012.
particular reaction that can control the coking through mod- Table 5.7 shows the evolution sulfur limit of diesel fuels
erating the condensation reactions via hydrogen transfer and in the United States, Europe, and Japan. In 2006, new U.S.
enhancing the thermal cracking and ring-opening reactions. standards for ultralow-sulfur diesel (ULSD) took effect under
The catalytic process is ideal; however, the catalysts a 2001 rule issued by the U.S. Environmental Protection
must be designed to function under severe conditions. Agency (EPA). Diesel fuel sulfur content must be reduced
Solvolytic and thermal reactions constitute another choice to no more than 15 ppm from the 500 ppm that was
to modify the feed. established by a 1993 rule that reduced the level from
5000 ppm (0.5 wt %). To account for pipeline contamina-
5.4.3 Finishing Processes tion, refiners may have to produce diesel fuel with a sulfur
5.4.3.1 Hydrotreatment content as low as 7 ppm. EPA estimates that the marginal
As a natural substance, crude oil contains heteroatom (S, N, cost of producing ULSD ranges from 2.5 to 6.8 cents
and O) compounds as well as metals (mainly Ni and V) in per gallon in the United States. The Energy Information
addition to hydrocarbons. The sulfur content of crude oils Administration (EIA) projects that the total investment in
normally ranges from 0.05 to 6 wt %, nitrogen content U.S. refineries to meet the requirements for ULSD ranges
varies from 0.1 to 1 wt %, oxygen from 0.1 to 2.0 wt %, and from $6.3 to $9.3 billion. Because the energy content of

Table 5.7—Limits of Sulfur Content of Diesel Oil in Europe, Japan, and in the United States
(in ppmw) [22]
1953 1976 1990 1992 1996 1997 2000 2005 2006 2011a

European Union – – – – 500 – 350 50 – 10

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Japan 12,000 5000 – 2000 – 500 – 50 – –

United States – – 500 – – – – – 15 –

Proposal of European Union commission.
a

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120 Petroleum Refining and Natural Gas Processing

ULSD is somewhat less than that of the 500-ppm sulfur the presence of 1.67 % H2S over CoMoS and NiMoS
content of diesel, fuel efficiency may be affected, requir- supported on acidic supports. Such supports are believed
ing higher demand on diesel and more consumption [23]. to enhance the sulfur release from active sites and the
Desulfurization of fuels is commonly achieved by hetero- hydrogenation of refractory sulfur species to accelerate
geneously catalyzed hydrodesulfurization (HDS), in which their deep desulfurization.
the organic sulfur species are converted to H2S and the
corresponding hydrocarbon: R-SH + H2 → R-H + H2S. Here 5.4.3.2 Product Blending
R represents an alkyl group, such as methyl (CH3–) or ethyl As a major finishing process, product blending plays a key
(C2H5–). The reactivity of R-SH compounds is higher than role in preparing the refinery products for the market in
that of disulfides (R-S-S-R). The H2S is easily removed compliance with all of the product specifications and quality
from the desulfurized oil by absorption in a gas treatment control measures. The objective of product blending is to
unit and subsequently converted to elemental sulfur by the assign all available blend components to satisfy the product
Claus process [24]. demand and specifications to minimize cost and maximize
Sulfur ring compounds such as methylated dibenzo- overall profit. Almost all refinery products are blended for
thiophenes have the lowest reactivity in HDS reactions the optimal use of all of the intermediate product streams
because of the shielding of the S atom by the methyl for the most efficient and profitable conversion of petro-
groups. Removing sulfur from these compounds (i.e., deep leum to marketable products. For example, typical motor
desulfurization) requires more hydrogen consumption to gasolines may consist of straight-run naphthas, crackates,
saturate the aromatic rings in dibenzothiophene to form reformates, alkylates, isomerates, polymerates, pyrolysis
nonplanar compounds and eliminate the steric hindrance gasoline, etc., in proportions to make the desired grades
of methyl groups to make the S atom accessible to active of gasoline and the specifications. Chapter 4 describes the
sites on the catalyst surface for removal as H2S. specifications of the petroleum fuels and materials and
Hydrodenitrogenation (HDN) is a similar process in Chapter 19 is devoted to discussing the fuel blending tech-
which hydrogen is used to remove nitrogen, and for this nology and management in petroleum refineries. Until the
reason during HDS the nitrogen content of fuels is also 1960s, the blending was performed in batch operations.
reduced. Pyridine (C5H5N) can be reduced to pentane With computerization and the availability of the required
(C5H12) and ammonia (NH3) by adding 5H2 in three steps equipment, online blending operations have replaced blend-
that consist of saturating the aromatic ring with 3H2 to ing in batch processes. Keeping inventories of the blending
form piperidine (C5H11N), a ring-opening reaction with one stocks along with cost and physical data has increased the
H2 to form amylamine (C5H11NH2), and forming n-pentane flexibility of and profits from online blending through opti-
by removing nitrogen as NH3 with one H2. The overall HDN mization programs. In most cases, the components blend
reaction is C5H5N + 5H2 → C5H12 + NH3. nonlinearly for a given property (e.g., octane number, cetane
Removal of basic nitrogen compounds such as C5H5N is number, freezing point), and geometric programming is
an important pretreatment step before a process that uses required for reliable predictions of the specified properties.
acidic catalysts, such as FCC. On the other hand, HDS is an
important pretreatment process for feedstocks that would be 5.4.4 Supporting Processes
exposed to noble metal catalysts that are poisoned by sulfur Supporting processes are not directly involved in the pro-
compounds, such as Pt in the catalytic reforming process. duction of fuels or materials, but they are essential for the

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HDS reaction conditions are typically 350°C and 7 MPa. operation of a petroleum refinery. Major supporting processes
With respect to the increasing demand for practically include hydrogen production, environmental remediation of
sulfur-free fuels (<10 ppm), sulfur species with very low refinery emissions, and sulfur recovery. Hydrogen produc-
reactivity such as dibenzothiophene derivatives have to be tion and environmental remediation issues are discussed in
converted in a second-stage deep HDS step that leads to detail in Chapters 12 and 29, respectively, and will not be
additional high investment and operating costs [22]. covered here. The following section reviews sulfur recovery.
Shih et al. [25] developed a simple correlation for pre- Sulfur exists in natural gas and refinery gases (i.e., over-
diction of reactivity over a temperature range of 520–780°F. head gas from crude distillation and hydrotreating units) as
The reactivity is defined as the temperature (°F) required to H2S. An acidic gas, H2S is removed by absorption in basic
achieve a 500-ppm sulfur product (T500ppmS) and is given as a solutions of ethanol amines and sent to the Claus process.
function of two feed properties: In the Claus process, H2S is converted to elemental sulfur,
which can be safely stored and sold as a byproduct. The
T500ppmS = 454°F + 31 exp(S600F+) + 25 ln(N) (5.2) process consists of two steps that take place consecutively in
burner and converter reactors. In the burner, part of H2S is
where: oxidized to form sulfur dioxide (SO2), which subsequently
S600F+ = weight percent of sulfur in the 600°F+ fraction reacts with the remaining H2S over an alumina catalyst in
of the feed, and the converter reactor to produce elemental sulfur [24]:
N = feed nitrogen content (ppmw). 3
For ULSD fuel (10 ppm sulfur), usually alumina- H 2S + O → SO2 + H2O (Burner reaction)
2 2
supported CoMo or NiMo-sulfide (NMA) catalysts are used.
An alternative to this is carbon-supported Ni-Mo-sulfide 2H2S + SO2 ↔ 2H2O + S (Converter reaction)
(NMC) with surface areas ranging from 900 to 3000 m2/g
as discussed in reference 26. Kunisada et al. [27] show that The overall reaction in the Claus process becomes
a hydrotreated gas oil containing 340 ppm sulfur can be
3
successfully desulfurized to less than 10 ppm sulfur under 3H2S + O → 3H2O + S
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Chapter 5 n Crude Oil Refining Processes 121

Because of equilibrium limitations, the sulfur recovery 1861 to 1975 as the development of the internal combustion
is usually limited to 94–95 %. Therefore, the Claus offgas engine has demanded the production of gasoline and diesel
contains small amounts of H2S, SO2, and other sulfur gases fuels, and the aviation industry has demanded high-octane
such as COS and carbon disulfide (CS2) formed in the side aviation gasoline for the turbo engine and kerosene-based
reactions. Using a separate process (e.g., the Shell Claus jet fuel for the gas turbine engine of jet aircraft. The increas-
Off-gas Treatment [SCOT]), SO2, COS, and CS2 are converted ing demand for distillate fuels that has exceeded the supply
to H2S upon reaction with hydrogen on a tungsten catalyst. that can be obtained from distillation alone has ushered in
The H2S product is absorbed by an amine solvent and thermal and catalytic conversion processes in addition to
recycled to the Claus unit feed. A combination of the Claus physical separation processes such as vacuum distillation
process with a tail gas clean-up process such as SCOT leads (1870), dewaxing (1935), and deasphalting (1950) to produce
to sulfur recovery in excess of 99 % [24]. lubricating oils along with byproducts such as wax and
asphalt that have found other industrial applications.
5.5 Evolution of Refinery Processes and In 1913, the thermal cracking process was developed
Refinery Configurations to break the large molecules into smaller ones to produce
5.5.1 Development of Refinery Processes additional gasoline and distillate fuels. Visbreaking and
Consumer demand has driven a continuous evolution of coking were developed in the late 1930s to treat the heavy
petroleum refining with the introduction of new processes ends. Catalytic cracking and polymerization processes
to increase the quantity and quality of refinery products in a were also introduced in the mid- to late 1930s to meet the
long path from producing just one main product, kerosene, by demand for higher octane gasoline required by the higher-
simple atmospheric distillation in 1861 with the byproducts compression gasoline engines. Other catalytic processes, such
tar and naphtha to the multitude of hydrocarbon fuels, as alkylation and isomerization, were developed in the early
chemicals, and petrochemicals produced in the complex 1940s to produce high-octane aviation gasoline and petro-
refineries of the present day. Table 5.8 shows a timeline of chemical feedstocks. Catalytic reforming and isomerization
the refinery processes introduced in the time period from were developed in the 1950s to increase the gasoline

Table 5.8—A Timeline for the Development of Petroleum Refining Processes from 1861 to
1975 [28]
Year Process Purpose Byproducts, etc.

1861 Atmospheric distillation Produce kerosene Naphtha, tar, etc.

1870 Vacuum distillation Lubricants (original) and cracking feedstocks (1930s) Asphalt, residual coker feedstocks

1913 Thermal cracking Increase gasoline Residual, bunker fuel

1916 Sweetening Reduce sulfur and odor Sulfur

1930 Thermal reforming Improve octane number Residual

1932 Hydrogenation Remove sulfur Sulfur

1932 Coking Produce gasoline basestocks Coke

1933 Solvent extraction Improve lubricant viscosity index Aromatics

1935 Solvent dewaxing Improve pour point Waxes

1935 Catalytic polymerization Improve gasoline yield and octane number Petrochemical feedstocks

1937 Catalytic cracking Higher octane gasoline Petrochemical feedstocks

1939 Visbreaking Reduce viscosity Increased distillate, tar

1940 Alkylation Increase gasoline octane and yield High-octane aviation gasoline

1940 Isomerization Produce alkylation feedstock Naphtha

1942 Fluid catalytic cracking Increase gasoline yield and octane Petrochemical feedstocks

1950 Deasphalting Increase cracking feedstock Asphalt

1952 Catalytic reforming Convert low-quality naphtha Aromatics

1954 Hydrodesulfurization Remove sulfur Sulfur

1956 Inhibitor sweetening Remove mercaptan Disulfides

1957 Catalytic isomerization Convert to molecules with high octane number Alkylation feedstocks

1960 Hydrocracking Improve quality and reduce sulfur Alkylation feedstocks

1974 Catalytic dewaxing Improve pour point Wax

1975 Residual hydrocracking and flexicoking Increase gasoline yield from residual Heavy residuals
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122 Petroleum Refining and Natural Gas Processing

Table 5.9—Evolution of the Demand for Petroleum Products in the World from 1970 to 2010 [30]
1970 1980 1990 2000 2010

106
10 6
106
10 6
106

tons % tons % tons % tons % tons %

Gasoline 492 25.4 626 26.6 750 26.8 876 26.2 1047 26.0

Middle 530 27.4 721 30.6 950 33.9 1163 34.8 1472 36.6
distillates

Heavy fuels 608 31.4 645 27.4 500 17.9 426 12.8 456 11.3

Others 307 15.8 363 15.4 600 21.4 875 26.2 1046 2.0

Total 1937 100 2355 100 2800 100 3340 100 4021 100
Middle distillates = jet fuels, heating oil, and diesel oil. Others = refinery gas, LPG, naphthas, lubricants, wax, bitumen, petroleum coke, etc. 1 bbl/day =
~50 t/year.

yields with high octane numbers and improve antiknock produced a large amount of fuel oils (~40 %). In the late
characteristics. Throughout the 1960s and 1970s, new 1970s, the oil shocks caused a decrease in the demand
catalysts were developed for hydrocracking and residue for heavy fuels and a need for lighter products. This was
hydrocracking processes to produce higher yields of light the main reason for using more cracking units such as
and middle distillates and for catalytic dewaxing to improve visbreakers, catalytic crackers (FCC), and hydrocrackers
the pour point of lubricating oils. to produce low-sulfur products. For example, in France,
In parallel to the development of conversion processes, 15 million t of fuel oil were used in 1973 whereas in 1993
various treatment (finishing) processes have been developed this number reduced to only 2 million t [29]. Heating oil
to remove heteroatoms and other impurities. Treating pro- has been largely replaced by gas and electricity. In France,
cesses can involve chemical reaction or physical separation nuclear power plants generate 75 % of electricity. In the
or both. Typical examples of such treating processes are meantime, the demand for the petroleum products with
chemical sweetening (1916), hydrogenation (1932), and no easy substitute such as gasoline and middle distillates
HDS (1954). continued to increase.
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Table 5.9 shows the evolution of the demand for petro-

5.5.2 Changes in Refinery Configurations leum products in the world from 1970 to 2010 as given
Until the 1960s and 1970s, refineries had relatively simple by Marcilly [30], clearly showing the significant drop in
configurations consisting primarily of distillation, cata- the demand for heavy fuels from 31.4 % of the petroleum
lytic reforming, and HDS units. Such simple refineries refined in 1970 to 11.35 % in 2010.

Figure 5.17—A refinery scenario for 2010. Source: Figure modified from Marcilly [30], a European model.
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Chapter 5 n Crude Oil Refining Processes 123

Figure 5.17 shows a flow diagram for the sophisticated In all three regions, hydrotreatment and cracking processes
and ultracomplex refineries of the present day [30]. The have been on the rise and the trend continues.
principal feature of these refineries is the high level of A future scenario for refineries in the United States is
conversion of heavy ends into light products. Most of the shown in Figure 5.18 [31]. In this scenario, a light Saudi
conversion takes place through FCC-type units with high Arabian crude is considered with a sulfur content of 1.78
yields of gasoline at low cost. In Western Europe conver- wt %. The produced gasoline has a sulfur content of 5–10
sion processes in refineries increased from 6 % in 1975 to ppm. In this scenario, coking provides the principal carbon
more than 30 % in 1977 [29]. In 1977, only one third of rejection as coke, and all of the liquid products from coking
143 refineries in Western Europe were equipped with FCC are further treated to manufacture light and middle distil-
units whereas in 2000 this is more than 80 %. Furthermore, lates and fuel oil. Further discussion on future scenarios for
environmental regulations require fuels with less sulfur, and petroleum refineries is given in Chapter 34.
production of ultralow-sulfur fuels (gasoline and diesel fuels)
is on the rise. The manufacturing of such high-quality fuels 5.6 Future Outlook—Markets and
requires more severe conversion and finishing processes in Technology
refineries. Table 5.10 shows the evolution of refinery pro- Factors that would affect future refineries over time include
cesses in various parts of the world for the last 20 years financing, technology, people/organizations, business, and
[30]. The figures represent capacity in million tons per year. the environment. Regardless of government regulations,

Table 5.10—Development in the Structure of World Refining Capacities from 1979 to 1999 for
the Main Geographical Zones in Million Tons per Year [30]
1979 1999

North America Western Europe Asia-Pacific North America Western Europe Asia-Pacific

HDT 437 346 214 577 404 374

FCC 260 49 30 298 106 125

HDC 46 6 1 84 34 35

Atmospheric distillation 997 998 520 923 723 982

HDT = hydrotreatment, HDC = hydrocracking.

Figure 5.18—A scenario for a future refinery for light Arabian crude (a U.S. model). Sulfur in the feed is 1.78 wt % and refinery
capacity is 150,000 bbl/day. Source: Figure modified after [31]. --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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124 Petroleum Refining and Natural Gas Processing

future refineries should have safer operations to prevent hydrogen consumption for classical refineries depends on
explosions, fires, spills, and environmentally undesirable the product quality.
emissions with strict commitment to the production plan The hydrotreatment required for deep conversion
and economical operation. demands additional hydrogen to supplement what was sup-
Petroleum refining involves physical and chemical pro- plied traditionally by the refinery reformer. The additional
cesses, and the complexity of refining depends on the crude sources of hydrogen include a natural gas steam-reforming
quality and the required specifications of the products. unit or partial oxidation of the residue to totally convert the
Crude quality varies from one part of the world to the other; residue into synthesis gas [30].
it also changes with time. Usually the crude quality in terms Looking ahead, five drivers have been identified as
of API gravity and sulfur content decreases with time. For having the greatest affect on the petroleum industry in the
example, the API gravity of crude oils refined in the United coming decades [32]:
States has decreased from 33.8 to 32.0 in the period of 1. Environmental concerns: Lifecycle effects of petroleum
1 decade from 1980 to 1990. During the same period, the fuels on air pollution and global climate change and
sulfur content of U.S. crudes has increased from 0.86 to continuously evolving regulations.
1.1 wt % [1]. Such quality changes require more advanced 2. Markets and demand: Strong demand for petroleum
crude refining. In conflict with the trend of crudes getting fuel and objectives to reduce this demand by replacing
heavier, on the product side in the past few decades there them with cost-effective and renewable energy sources.
has been higher demand on distillates such as gasoline, jet 3. Competitive forces: Increased global competition leading
fuel, and diesel fuel and less demand on heavy fuel oil and to joint ventures and mergers to reduce cost.
residues. This conflict, along with the environmental regu- 4. Process improvements: Capability to respond to changes
lations that demand cleaner fuels, requires more extensive in the crude slate with more sophisticated and new
conversion processes to transform heavy oils into lighter technology, including new catalysts, new chemistry
and cleaner products. and concepts in refining, and modeling technologies
A high-sulfur and heavy crude costs up to one third interfaced with online measurement technologies for
less than lighter or better crudes. However, high-sulfur optimization.
crudes require more processing and therefore more fixed 5. Energy efficiency: New technologies, market incentives,
expenses and labor. They also require more energy. Energy and increasing scale of operations to improve energy
accounts for roughly half of the operating cost of a refinery. efficiency and increased engine efficiencies driven by
A refinery close to crude oil sources and a high-demand mandates and competitive forces as well as opportuni-
market entails lower transportation cost. A refinery can ties for treating an engine-fuel combination as a single
make good profits if it is well equipped to run some of entity to increase the efficiency of gasoline and diesel
the heaviest, cheapest crudes in the world. Large invest- engines.
ments are needed to meet the environmental constraints With these major drivers, future refineries will become
and product quality (i.e., high-octane unleaded gasoline, safer, more reliable, more energy-efficient, and have reduced
ultralow-sulfur fuels). To increase the octane number of environmental impact. A high degree of automation with
gasoline without the use of TEL, refineries must oper- integrated process and energy systems control could effec-
ate at greater severity for catalytic reforming, have more tively address the changing product specifications and
isomerization and alkylation units, and use oxygenated respond to the market demand [32]. Further discussion on
compounds as additives. Changing market conditions also these issues is provided in Chapter 34.
affect future refineries.
The evolution of investment, energy consumption, and 5.7 Summary
hydrogen consumption for three categories of refineries as Petroleum refining has evolved from a one-pot batch dis-
of 2000 in the European Union is given in Table 5.11 [30]. tillation process to separate kerosene from crude oil for
The cost of refinery investment as well as the amount of lighting lamps to the most sophisticated network of inte-
grated physical and chemical processes that run around the
Table 5.11—Evolution of Investment, clock. These processes separate crude oil into hydrocarbon
Energy, and Hydrogen Consumptions for the fractions and convert/finish these fractions into a multitude
Refineries of 2000 [30] of commercial fuels and materials. The primary objective
of a petroleum refinery is to add value to a crude oil feed
Energy by producing marketable fuels and materials at the lowest
Type of Investment Consumption Hydrogen possible cost in accordance with the required product
Refinery (billion $) (wt % of crude) Consumptiona
specifications and environmental regulations.
Simple 0.5 ≈4 α The refinery products include LPG, gasoline, solvents,
jet fuel, diesel fuel, fuel oil, asphalt, wax, lubricating oils,
Classical 1–1.5 ≈6 2α
conversion
and petrochemicals. Considering the variability of crude
oils with geography and time and the evolving demand,
Deep 2.5 ≈ 10 5α specifications, and environmental regulations for the refinery
conversion products, refineries need to have the flexibility to handle
a
The figures are not absolute because the hydrogen and therefore Â these variations in a competitive market. This chapter
will depend on operating conditions (nature of crude and S content provides an overview of how refinery processes work and
of products, etc.). Investment costs are given for a typical refinery of relate to one another to make use of physical separations
~150,000- to 160,000-bbl/day capacity.
and chemical changes to provide the market with the
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Chapter 5 n Crude Oil Refining Processes 125

desired quantity and quality of the petroleum products. [17] “UOP Par-Isomer™ Process,” http://www.uop.com/clean-fuel-
Most innovations in petroleum refining processes took specifications-met-light-naphtha-isomerization-technologies-
uop/ (accessed February 19, 2012).
place around the time of World War II and often with the
[18] Gary, J.H., Handwerk, H., and Kaiser, M.J., Petroleum Refin-
collaboration of several oil companies to meet the demand ing: Technology & Economics, 5th ed., CRC Press, Boca Raton,
for the higher quantity and higher quality of distillate FL, 2007, p. 161.
fuels. The recent increase in the demand for distillate fuels, [19] “A Two-Stage Hydrocracking Process,” http://www.uop.com/
particularly in Asia, could initiate another wave of innova- hydrocracking-unicracking-stage/ (accessed February 20,
tions in refinery operations to exploit the breakthroughs in 2011).
[20] “UOP Merox™ Process,” http://www.uop.com/processing-
digital communications and process modeling to yield the solutions/refining/gas-lpg-treating/ (accessed February 20, 2011).
demanded products under the current environmental and [21] U.S. Title 40, Part 80 40 CFR 80 § 500-620, http://ecfr.
feedstock constraints. gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&sid=e8e7d79c681c4a
6fa6a64275952d9c3f&rgn=div6&view=text&node=40:16.0.1.1
References .9.9&idno=40 (accessed February 20, 2011).
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ed., Marcel Dekker, New York, 2006. of Diesel Oil: Kinetic Studies and Process-Improvement by the
Use of a Two-Phase Reactor with Presaturator,” Chem. Eng.
[2] Manning, F.S., and Thompson, R.R., Oilfield Processing,
Sci., Vol. 59, 2004, pp. 2821–2829.
PennWell Publishing, Tulsa, OK, 1995.
[23] Andrews, A., Oil Shale: History, Incentives, and Policy, Con-
[3] Geankoplis, C.J., Transport Processes and Separation Process
gressional Research Service Report for Congress, Library of
Principles, 4th ed., Prentice Hall, Upper Saddle River, NJ, 2003.
Congress, Washington, DC, 2006.
[4] McCabe, W.L., Smith, J.C., and Harriott, P., Unit Operation of
[24] Gary, J.H., Handwerk, H., and Kaiser, M.J., Petroleum Refin-
Chemical Engineering, 7th ed., McGraw-Hill, New York, 2005.
ing: Technology & Economics, 5th ed., CRC Press, Boca Raton,
[5] Kister, H.Z., Distillation Operations, McGraw-Hill, New FL, 2007, pp. 283–290.
York, 1990.
[25] Shih, S.S., Mizrahi, S., Green, L.A., and Sarli, M.S., “Deep
[6] Siemanond, K., and Kosol, S., “Retrofit of Crude Preheat Train Desulphurization of Distillates,” Ind. Chem. Res., Vol. 31,
with Multiple Types of Crude,” in SIMULTECH11 Proceedings, 1992, pp. 1232–1235.
2011, pp. 303–308.
[26] Kouzu, M., Kuriki, Y., Hamdy, F., Sakanishi, K., Sugimoto, Y.,
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portation, Wiley-VCH, Weinheim, Germany, 2008, pp. 29–34.

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Sulfide for Ultra-Deep Hydrodesulfurization of Diesel Fuel,”
[8] Gary, J.H., Handwerk, H., and Kaiser, M.J., Petroleum Refin- Appl. Catal. A, Vol. 265, 2004, pp. 61–67.
ing: Technology & Economics, 5th ed., CRC Press, Boca Raton, [27] Kunisada, N., Choi, K.-H., Lorai, Y., and Mochida, I., “Effec-
FL, 2007, p. 83. tive Supports to Moderate H2S Inhibition on Cobalt and
[9] “UOP/FWUSA Solvent Deasphalting Process,” http://www.uop. Nickel Molybdenum Sulfide Catalysts in Deep Desulfurization
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[10] “U.S. Energy Information Administration, U.S. Depart- [28] “OSHA Technical Manual, Section IV: Chapter 2,” http://www
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data_publications/petroleum_marketing_monthly/pmm.html ary 20, 2011).
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February 19, 2012). Paris, 1995, p. 504.
[12] “UOP CCR Platforming™ Process,” http://www.uop.com/ [30] Mracilly, C., “Evolution of Refining and Petrochemicals: What
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[13] Gary, J.H., Handwerk, H., and Kaiser, M.J., Petroleum Refin- pp. 499–514.
ing: Technology & Economics, 5th ed., CRC Press, Boca Raton, [31] Lamb, G.D., Davis, E., and Johnson, J.W., “Impact of Future
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[14] “CCR Platforming,” http://www.uop.com/refining/1031.html w w w. m u s t a n g e n g . c o m / A b o u t M u s t a n g / P u b l i c a t i o n s /
(accessed February 20, 2011). Publications/IMPACT.pdf (accessed October 2, 2012).
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(accessed February 20, 2012). on February 22, 2011).

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6
Fluid Catalytic Cracking
Ravi Kumar Voolapalli1, Chiranjeevi Thota1, D.T. Gokak1, N.V. Choudary2, and M.A. Siddiqui3

6.1 Introduction place. In this section, gas oil feed streams are converted to
Fluid catalytic cracking (FCC) is a major secondary pro- gasoline, LPG, cycle oils, gas, and coke. The main fraction-
cessing unit in the petroleum industry for converting gas ator separates the cycle oils and bottoms whereas the off-
oil streams into high-octane gasoline, cycle oils, liquefied gas, light olefins, and gasoline are separated from unstable
petroleum gasoline (LPG), and light olefins. After the car- gasoline in the gas concentration section.
bon rejection route, it upgrades low-value streams such as The riser-reactor section consists of three key compo-
vacuum gas oil (VGO), atmospheric residue, deasphalted nents: the riser, stripper, and catalyst regenerator. In the
heavy oils, etc., into distillates while operating at low pres- riser section, gas oil feed comes in contact with hot regen-
sures and moderate temperatures. It has gained a special erated catalyst, feed vaporizes in the first few metres, and
place in the refining industry because of its feed flexibility, concurrently starts cracking as it moves upward along with
ability to produce diverse products, and quick response to the catalyst. A substantial amount of enthalpy is consumed
the market demands through minor changes in process from the hot catalyst for feed vaporization and endother-
operating conditions. The economics of the FCC process mic cracking reactions leading to a drop in temperature
are so attractive that it is almost impossible to imagine a and thus reduced cracking severity. The cracking reactions
modern refinery without this unit. also produce a significant amount of coke, due to which the
catalyst loses its activity. Therefore, continuous regenera-
6.2 History tion of catalyst is vital. The spent catalyst is regenerated by
FCC technology was originally developed nearly 70 years burning the deposited coke in the regenerator. Because of
ago, primarily for producing gasoline from gas oil feed- the exothermic heat of coke combustion, the catalyst tem-
stocks [1]. The first FCC unit was commissioned in 1942 at perature increases in the regenerator. The enthalpy carried
the Esso refinery in Baton Rouge, LA, using powder cata- by the hot catalyst is the only source of heat for vaporiza-
lyst that was made to flow like a liquid through fluidization. tion and cracking the feed in the riser. Before entering the
The world’s leading oil-producing and technology com- regenerator, the spent catalyst is efficiently separated from
panies such as M.W. Kellogg, Standard Oil (Indiana), BP, the product stream in the riser termination section and
Royal Dutch/Shell group, Texaco, and UOP undertook this steam is stripped to remove the adsorbed hydrocarbons so
challenging task through a consortium approach employing that the load on the regenerator is only due to hard coke.
approximately 1000 scientific and technical personnel. It The product stream separated from the catalyst leaves
was the first time in the history of mankind that such large- the riser and enters the bottom section of the main fraction-
scale fluidized reactors were built and solids were made ator, where it is quenched in the column’s bottom circuit pro-
to flow like liquid. Since then, technological innovations ducing medium-pressure steam. In the main fractionators,
have continued over the years for improved operation ease, light cycle oil and heavy naphtha are separated as side draws
product selectivity, and feed flexibility, thus spreading the whereas unconverted heavy slurry oil is removed from the

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scope of this process in a substantial way [2]. Today, petro- bottom. The gas, condensed water, and unstable gasoline are
leum refiners are viewing FCC not as a high-octane gasoline recovered from the column top through a partial condenser.
production unit alone but also as a major source for light In most applications, the bottom product is used as such
olefins and petrochemical feedstock production as well as except when the catalyst fines content is high, necessitat-
an important option for upgrading resid feeds. ing some type of filtration. The bottom product is used as a
cutter for fuel oil production or finds application as carbon
6.3 Process Description black feedstock. The main fractionator bottom temperature
FCC is a selective cracking process for converting high- is maintained below 370°C to avoid coking while the column
molecular-weight hydrocarbon molecules, typically gas oil top pressure is typically approximately 1.5 bar.
range, into low-molecular-weight compounds using crys- The uncondensed vapor stream mainly contains gas,
talline zeolite, a silica alumina-based catalyst. Figure 6.1, LPG, and gasoline. The vapors are compressed in a two-
shows the process scheme of a typical FCC plant. Concep- stage compressor to a pressure of 15 bar and enter a high-
tually, the process can be divided into three main sections: pressure separator (HPS) system. The gases from the HPS
the riser-regenerator section, the FCC main fractionator, are contacted in the primary absorber with unstabilized
and the gas concentration unit. The riser-reactor section is gasoline and debutanized gasoline to remove the C3+ frac-
the heart of the process where the cracking reactions take tion from the C2– fraction. The offgases from the primary

1
Bharat Petroleum Corp., Ltd., Greater Noida, India
2
Hindustan Petroleum Corp., Ltd., Beguluru, India
3
Guru Gobind Singh Indraprastha University, New Delhi, India
127
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128 Petroleum Refining and Natural Gas Processing

10
Offgas to
absorber
6 7
Flue gas to
CO-boiler 2
8 9
12
Heavy naphtha 11
1

C3/C4
LCO
3
13
5

HCO
Preheated
air Steam LG

14
Fresh feed Clarified slurry oil
Steam MCB

HG
4 Slurry oil
C3/C4= LPG cut
LG = Light gasoline
HG = Heavy gasoline
LCO = Light cycle oil
HCO = Heavy cycle oil
MCB = Main column bottom

1 = Regenerator, 2 = FCC reactor, 3 = fractionator, 4 = slurry settling drum, 5 = LCO stripper, 6 and 7 = compressor
stage I and II, 8 = overhead product collection drum, 9 = interstage collection drum, 10 = air fin cool system, 11 =
high-pressure separator, 12 = stripper, 13 = debutanizer, 14 = gasoline splitter.

Figure 6.1—FCC complex configuration including product separation.

absorber are sent to the sponge oil absorber wherein light Catalytic cracking chemistry is based on carbenium
cycle oil (LCO) is used as absorbing media to remove C5+ ion formation, stabilization, and termination. The basic
and LPG from the offgases. The gas with most of the C3+ mechanism involves initiation of a charged carbon atom
material removed is treated for H2S removal or sent for fur- on either a Bronsted or Lewis acid site by protonation
ther processing before using as fuel gas. The liquid stream or abstraction of hydrogen ion. Propagation then occurs
from the HPS is fed to a stripper column for the removal by hydride transfer and cracking by β-scission (cracking
of C2– and sent back to the HPS. The C3 and C4 compounds at two bonds away from the carbenium ion). Cracking
in the stripper bottoms are separated in a debutanizer col- reactions involve C–C bond rupture via formation of car-
umn. The stabilized gasoline from the debutanizer bottom, bocations. A scheme for cracking via carbenium ion inter-
which is free from C3 and C4, is sent to further treatment or mediate is as follows:
storage. The FCC main fractionator and gas concentration 1. Initiation (making the carbenium ion)
section designs are more or less the same in almost all FCC
R1-CHCH-R2 + H+ ↔ R1-C+H-CH2-R2 (6.1a)
units. However, there have been significant differences in
Olefin Bronsted acid site Carbenium ion
the reactor regenerator section, especially with respect to
R1CH2-CH2-R2 – H- ↔ R1C+H-CH2-R2 (6.1b)
the configurations and integration of various subsystems.
Paraffin Lewis acid site Carbenium ion
These differences are primarily due to different patented
licensor designs, product pattern, processing conditions 2. Propagation step (hydride transfer)
used, and the quality of feeds handled.
R1-CH2-C+H-R2 + R3-CH2-CH2-R4 ↔ R1-CH2-CH2-R2
6.4 Major Reactions Carbenium ion Paraffin Paraffin
In the FCC riser section, a wide range of complex series + R3-CH2-CH+-R4 (6.2)
and parallel reactions occur, which include primary gas oil Carbeniumion
cracking reactions and secondary reactions such as hydro-
3. Cracking step (β-scission)
gen transfer, isomerization, dehydrogenation, cyclization,
etc. [3]. Table 6.1 summarizes the key reactions and the R3-CH2-CH+-R4 → R3+ + CH2CH-R4 (6.3)
thermodynamic data for a few idealized reactions. --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Carbenium ion Carbenium ion Olefin
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Chapter 6 n Fluid Catalytic Cracking 129

Table 6.1—Key Reactions and Thermodynamic Data for a Few Idealized Reactions [4] Primary
Cracking Reactions
Heat of Reaction
Reaction Class Reactions Example Btu/mol (∆HR) 950°F

Cracking Paraffins → Olefin + Paraffin n-C10H22 → n-C7H16 + C3H6 32,050

Olefins → Olefins
1-C8H16 → 2-C4H8 33,663
Naphthene → Olefins

Dealkylation Alkyl Aromatic → Olefin + Alkyl Aromatic iso-C3H7-C6H5 → C6H6 + C3H6 40,602
(cracking)

Secondary reactions

Hydrogen transfer Olefin + Naphthene → Paraffin + Cyclo-Olefin 2C6H12+2C6H12 → 3C6H14+C6H6 –109,681

Carbenium Ion + Paraffin → Paraffin + Carbenium Ion RCH(+)CH2CH3 + R/CH2CH3 → –

RCH2CH2CH3 + R/CH(+)CH3

Naphthene + Olefin → Aromatic+ Paraffin Cyclo-C6H12 + C5H10 → C5H12 + C6H6 –73,249

Isomerization n-Olefin → iso-Olefin 1-C4H8 → trans-2-C4H8 –4,874

n-Paraffin → iso- Paraffin n-C6H10 → iso-C4H10 –3,420

Alkyl-o-Aromatics → Alkyl-m-Aromatics o-C6H4(CH3)2 → m-C6H4(CH3)2 –1,310

Naphthenes → Alkyl Naphthenes cyclo-C6H12 → CH3- cyclo-C5H9 6,264

Transalkylation C6H6+m-C6H4(CH3)2 → 2C6H5CH3 –221

Cyclization Olefin → Naphthenes 1-C7H14 → CH3-cyclo-C6H11 –37,980

Dehydrogenation Naphthenes → Cyclo Olefins, Aromatics n-C6H14 → 1-C6H12+H2 –

Aromatics → Multi-Ring Aromatics –

Polymerization 3C2H4 → 1-C6H12 –

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Paraffin alkylation 1-C4H8+iso-C4H10 → iso-C8H18 –

4. Termination (final step) reactions proliferate at high temperatures, producing more

aromatics and olefins. Paraffin isomerization with less
R5-CH2-CH+-R6 → R5-CH2-CHCH2-R6 + H+ (6.4)
branching is more favorable under FCC conditions [5].
Carbenium ion Olefin Acid site
Thermodynamically, polycondensation reactions are
not favored under cracking conditions (i.e., low pressure
Primary and secondary carbenium ions tend to rear- and high temperature). However, coke is formed through
range to form a tertiary ion; hence, catalytic cracking leads polymerization of unsaturated compounds followed by
to formation of more branched compounds. The nature and dehydrogenation by acid hydrogen transfer or catalyzed by
strength of the catalyst acid sites will influence the degree metallic impurities. Other pathways suggested were alkyla-
of occurrence of various reactions. The stability of carbocation of aromatics followed by cyclization or condensation
tions depends on the nature of alkyl groups attached to the of olefins and diolefins and subsequent dehydrogenation.
positive charge. The relative stability of carbenium ions is Although there are quite a few exothermic reactions in FCC,
as follows: because of the predominance of cracking and dealkylation
reactions, the net reactions are endothermic. Further, cata-
Tertiary > Secondary > Primary > Ethyl > Methyl (6.5)
lysts with less hydrogen transfer activity will cause the net
Catalysts with high acidity are required for enhanced heat of reaction to be more endothermic, requiring higher
cracking, but they also promote hydrogen transfer reactions. amounts of catalyst circulation. Thus, temperature and
Unfortunately, a hydrogen transfer reaction would lead to type of catalyst have a significant effect on the product yield
lower gasoline octane and higher coke make. For exam- pattern and FCC heat balance.
ple, rare-earth-exchanged zeolites produce more paraffins
and aromatics compared with ultrastabilized zeolite-based 6.4.1 Kinetics of Catalytic Cracking and Coke
catalysts. For maximization of light olefins, catalysts are Combustion Reactions
tailored to minimize the hydrogen transfer reactions. Like- FCC feed consists of a wide boiling mixture of heavy-
wise, temperature has an important role in governing the hydrocarbon molecules, the reactivities of which differ
type of compounds produced. High temperatures encour- considerably according to individual hydrocarbon type
age more cracking and less hydrogen transfer, because of and molecular weight. Naphthenes and paraffins have a
which the coke production is relatively low. Dealkylation higher cracking tendency over aromatics, whereas heavier
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130 Petroleum Refining and Natural Gas Processing

olecules crack faster than the lighter ones. The crack-

m in which A is a function of feed quality and n is a con-
ing reactions of FCC feed, which consists of diverse stant dependent on the type of catalyst. Zeolite-rich cata-
compounds, follow pseudo second-order kinetics. This is lysts typically yield more coke initially (lower n value)
because the feed becomes progressively difficult to crack compared with amorphous-rich catalysts. After a certain
with increasing conversion levels. For plug flow systems, cross-over contact time, the amorphous-rich catalyst coke
the conversion severity relation can be modeled through Eq will continue to increase whereas the zeolite catalyst coke
6.6 [6,7]. The feed crackability increases with the increase value tapers off. Hence, while comparing the commercial
of nonaromatic content and increasing size of the hydro- plant coke yields with small-scale microreactors such as a
carbon chain (Nc), whereas feed nitrogen compounds (NN) microactivity test (MAT) unit, it is important to match the
inhibit the cracking. commercial plant contact times in the microreactor to have
realistic coke yields.
X It may be noticed from Eqs 6.6 and 6.8 that for a given
WHSV = kC ( catalyst type) F ( feed crackability)
100 – X feed and catalyst, the second-order conversion and the coke
 E  m yields are only functions of catalyst residence time. There-
ex
xp  –  tc (6.6)
 RT  fore, at constant catalyst residence time, a linear relation
is expected among coke yield and second-order conversion
F ( feed crackability) = w1 ( NC – NC CA ) + w2 NN + w3 (6.7) [9,10]. Bollas et al. [7] proposed an equation for coke yield
(ux) similar to Eq 6.6 with a different activation energy (Eu)
where: and coefficient (nu) for catalyst residence time:
X = weight percentage conversion (total yields of liquid
fraction boiling below 221°C, coke and gas products); ux WHSV = ku Cu ( catalyst type)
WHSV = weight hourly space velocity (h-1);
 E 
k = kinetic constant (h-1); Fu ( feed coking tendency) exp  – u  t nu (6.9)
tc = catalyst residence time (h);  RT 
E = activation energy (kJ);
T = average temperature (K); 6.4.1.2 Gasoline
NC = carbon number of the average hydrocarbon molecule; The gasoline yield is a nonlinear function of conversion.
NN = number of nitrogen atoms in the average hydrocarbon The yield increases with conversion and reaches a maxi-
molecule; mum after which the yield reduces because of gasoline
CA = aromatic carbon content; overcracking (Figure 6.3). The maximum gasoline yield
C and F = functions of catalyst and feed properties, respec- is a function of reactor operational severity, catalyst, and
tively; and feedstock. Among saturates, naphthenic feeds are the most
m, w1, w2, and w3 = correlation constants. preferred for gasoline production. By hydrogen transfer
reactions, a large proportion of naphthenes are converted
6.4.1.1 Coke into monoaromatics, thus enhancing the octane. In con-
The coke yield of an FCC unit is primarily a function of trast, paraffin-rich feeds produce more LPG and low-octane
conversion, temperature, and feedstock characteristics and straight-chain paraffins.
can be correlated to second-order conversion as shown in The gasoline yield is also affected by the ZSM-5 content
Figure 6.2. Through extensive studies, Voorhies [8] sug- in the catalyst. ZSM-5 selectively cracks the low-octane
gested that coke on catalyst (CC) is primarily influenced by
1
the exposure time (Tc) and can be related through a nonlin-
ear relationship,

Cc = A·Tcn (6.8)
0.8

Gasoline
Gas
Yield, Wt. fraction

0.6
Coke

0.4

0.2

0
0 0.2 0.4 0.6 0.8 1
Figure 6.2—Coke yield vs. second-order conversion with Conversion, Wt. frac.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

different feedstocks [9]. Source: Figure used with permission

from Exxon Mobil. Figure 6.3—Gasoline, coke, and gas yield vs. conversion [11].
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Chapter 6 n Fluid Catalytic Cracking 131

PI = Wt. % paraffinic molecules, (mass spec analysis), 430–650ºF

Nl = Wt % naphthenic molecules, (mass spec analysis), 430–650ºF
CAl = Wt. % carbon atoms among aromatic rings, (n-d-M method), 430–650ºF
Al = Wt. % aromatic substituent groups (430–65OºF)
Pl = Wt. % paraffinic molecules, (mass spec analysis), 65OºF+
Nh = Wt. % naphthenic molecules, (mass spec analysis), 650ºF+
CAh = Wt. % carbon atoms among aromatic rings. (n-d-M method), 650ºF+
Ah = Wt. % aromatic substituent groups (650ºF+)
G = Glump (C5–430ºF)
C = Clump (C, to C4 + COKE)
CAl + Pl + Nl + Al = LFO (430–650ºF)
CAh + Ph + Nh + Ah = HFO (650ºF)
Figure 6.4—Ten-lump kinetic model of Jacob et al. [12]. Source: Figure used with permission from Exxon Mobil.

straight-chain paraffins and olefins into LPG. The LPG with respect to oxygen concentration and coke content on
yield increases linearly with ZSM-5 content in the catalyst. catalyst (reaction I and II of Figure 6.5). During combus-
The combined yields of gasoline and LPG increase almost tion, carbon monoxide (CO) and carbon dioxide (CO2) are
linearly with conversion. produced at the catalyst surface, and their distribution is
given by Eqs 6.10, 6.11, and 6.12 [10,13].
6.4.1.3 Gas
FCC dry gas is primarily produced because of thermal dC  – Ec 
cracking of the feed and nonselective catalytic cracking; – = r1 + r2 = kc 0 exp   ρc (1 – ε) CPO2 (6.10)
dt  RT 
hence, the yields are mainly affected by riser temperatures
and feed residence time. Minimizing the residence time
helps in substantially reducing the gas yields. The metal CO k1  Eβ 
= = β co exp   (6.11)
content on the catalyst also contributes significantly to CO2 k2  RT 
surface
the gas and coke production through dehydrogenation
reactions.
Rigorous kinetic models attempt to model the cracking β c kc kc
kc = k1 + k2, k1 = , k2 = (6.12)
reactions in a more detailed manner through a lumping βc + 1 βc + 1
approach that is based on detailed feed characteristics.
Figure 6.4 shows the ten-lump model of Jacob et al. [12]. Hydrogen combustion can be assumed to be instantaneous
Considering kinetics and reactor hydrodynamics, these (reaction IV of Figure 6.5), whereas combustion of CO
rigorous models more accurately predict the FCC yields can occur on the catalyst surface and in the homogenous
when tuned with sufficient experimental data and are very gas phase (i.e., within the void volume). CO conversion
useful in tracking the effect of operating parameters or feed is a free radical reaction and hence its combustion rate is
changes. relatively slower in the presence of surfaces such as cata-
lyst. The degree of inhibition is a function of temperature,
6.4.1.4 Kinetics of Coke Combustion catalyst size, and concentration [10]. Once the catalyst is
The coke burning kinetics are relatively less complex. There removed (in cyclones), if excess oxygen (O2) is present, CO
are four (I to IV) key reactions that occur during coke ignition takes place. This effect is known as “afterburn”
burning (Figure 6.5). Coke burning kinetics are first order and is important to control because high temperatures
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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132 Petroleum Refining and Natural Gas Processing

CO2 I: C k1
+ 0.5O2 → CO
Coke 2
k2
(CxHy) II : C + O2 → CO2
3
k3 c
1
III c : C O + 0.5 O2 → CO2
4 CO III h : C O + 0.5 O2 → k3 h
CO2
k4
H 2O IV : H 2 + 0.5 O2 → H 2O

Figure 6.5—Key reactions of coke burning.

can damage the cyclones. To enhance the CO burning Ec, Eβ, E3c, and E3h = activation energies corresponding to
within the dense catalyst bed, CO combustion promoters equations (kJ/K) (6.10–6.13).
are added. The effect of CO combustion promoters can be The coke combustion kinetic parameters are a func-
accounted for through k3h as shown in Eq 6.13. The net CO tion of the catalyst properties and remain constant as long
and CO2 production can be estimated by simultaneously as equilibrium catalyst properties (apparent bulk density
solving Eqs 6.10–6.13. [ABD], pore volume, surface area, and fines content) are
relatively constant [14].
  –E   –E  
r3 =  k3 c 0 exp  3 c  ρ c (1 – ε) + k3 h0 exp  3 h  ε  CPO2 PCO
  RT   RT   6.5 Feed, Product Quality, and Operating
(6.13) Conditions
FCC can handle various feedstocks, such as straight-run
where: and VGO streams, hydrotreated VGO, solvent deasphalted
C = coke on the catalyst, (weight coke/weight catalyst); oil, coker gas oil, portions of atmospheric or vacuum col-
PO2 and PCO = partial pressures of O2 and CO, respectively umn bottoms, and other heavy materials. The typical FCC
(Pa); feed boiling range is from 350 to 580°C, and densities are
kc = total coke combustion rate constant (1/Pa·s); normally greater than 0.87. Table 6.2 presents some of the
k1 and k2 = coke combustion reaction rate constants in reac- FCC feeds processed in industry.
tions I and II, respectively (Figure 6.5); Lower feed density values indicate a higher degree of
∈ = regenerator bed porosity; hydrocarbon saturation and hydrogen content. The prod-
ρc = catalyst density (kg/m3); uct yields and product quality of an FCC unit are directly
βc = CO/CO2 ratio at the catalyst surface; related to the feed hydrogen content. Hydrogen-rich par-
kc0 and βc0 = pre-exponent constants for kc and βc, respec- affins and naphthenes produce more gasoline compared
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

tively; with aromatic feeds, which are difficult to crack. Figure 6.6
k3c0 = pre-exponent constant for catalytic combustion in shows the feed conversions with variations in feed density
reaction IIIc; [15] along with the potential conversion values. Potential
k3h0 = pre-exponent constant for homogenous combustion conversions were calculated based on the paraffin and
in reaction IIIh; and naphthene content of the feed. The actual conversions are

Table 6.2—Typical FCC Feedstocks Processed in Industry

Nigerian VGO Mumbai VGO Hydrotreated VGO

Density, kg/L 0.9265 0.8811 0.8524

Sulfur, % wt 0.37 0.58 0.015

Total nitrogen % wt 0.1413 0.0726 0.0037

Conradson carbon, % wt 0.4 0.49 0.03

Nickel (Ni) (ppm wt) 0.55 0.53 —

Vanadium (V) (ppm wt) 0.08 0.32 —

Sodium (Na) content (ppm wt) 0.33 0.24 —

Distillation D-1160 (°C)

5% 370 372 358

30 % 403 419 407

50 % 438 442 427

95 % 539 552 506

Final boiling point (FBP) 572 581 530

AST-MNL58-11-0801-006.indd 132 3/12/13 2:01 PM

Chapter 6 n Fluid Catalytic Cracking 133

Figure 6.6—Conversion variation with changes in feed density. Source: Reproduced with permission from [14].

lower than the potential figures because of limitations of feed to compensate for the metal deactivation. Therefore,
either air blower or gas compressor capacity. In addition beyond a point (>10 wt %), it is uneconomical to process
to feed density, aniline point and refractive index are also high-CCR feeds and hence feed should be pretreated to
commonly used to assess the feed aromaticity and they reduce the CCR content (e.g., by hydroprocessing or solvent
correlate well with feed conversion. Aniline point increases deasphalting).
with paraffin content, whereas aromatics will have a lower Another important feed property that affects the feed
value [16]. Likewise, the refractive index increases with crackability is organic nitrogen, especially basic nitrogen
increase in aromaticity [17]. content, which has a detrimental effect on zeolite by tem-
Aromatic-rich feeds produce less gasoline and yield porarily inhibiting the acid sites of the catalyst. The activity
more LCO and coke. The LCO is of poor quality, whereas is regained by burning the nitrogen in the regenerator. To
the gasoline octane is high because of high aromatics. overcome the nitrogen inhibition, higher catalyst activity
Figure 6.7 shows the pilot plant data of Bollas et al., in and catalyst-to-oil ratio are needed.
which the crackability and coke selectivity exhibited strong Hydrotreating is a useful option for reducing nitrogen
correlation with feed aromaticity. When the feed boiling inhibition and metal deactivation as well as for improving
ranges differ widely, correlations based on UOP or Watson product quality. The yields of aromatic-rich feedstocks can
K factor, calculated from average boiling point and density, be substantially improved by subjecting them to either mild
or PONA content are expected to be more accurate [15]. hydrotreating or hydrocracking upstream and integrat-
Higher feed distillation temperatures and Conradson ing with FCC. The key benefits of feed hydroprocessing
carbon (CCR) content indicate the presence of residue, are higher gasoline yields, lower coke and gas make, and
metals, and asphaltene in the feed. Handling high-CCR improved quality of distillates (w.r.t. sulfur content and
feeds is difficult because they tend to produce more coke, LCO cetane). Sulfur is not inhibitory to the catalyst. How-
leading to higher regenerator temperatures, which limits ever, its removal helps in meeting the product quality on
their processability. Because of their high viscosity and high most occasions without further treatment and also helps in
boiling points, heavy hydrocarbons pose a challenging task reducing sulfur oxide (SOx) and nitrogen oxide (NOx) emis-
of vaporization at the riser entry and significantly affect the sions. The benefits due to feed hydrotreatment for improv-
yield pattern. Further, heavier feeds also contain a higher ing yield and quality can be seen in the data presented in
level of metals, which require more catalyst per barrel of Table 6.3 [18].

1.5 2.2

1.8
Coking Selectivity

1.2
Crackability

1.4

1
0.9

0.6

0.6 0.2
0 10 20 30 40 0 10 20 30 40
Aromatic Carbon wt% Aromatic Carbon wt%

Figure 6.7—Crackability and coking tendency dependency on feed aromatic content. Source: Reproduced with permission from [7].
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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134 Petroleum Refining and Natural Gas Processing

naphthenes and paraffins are produced in the feed, which

Table 6.3—Benefits of Hydrotreating on leads to higher LPG, gas make, and reduced gasoline yields
FCC Yields [18] with lower octane.
Untreated Hydrotreated
Feed Feed

Conversion, vol % 55.9 74.8

6.6 Modes of FCC Operation
In addition to feed flexibility, the FCC process also offers
Gasoline, vol % 39.6 55.1 versatility with respect to product slate. By appropriate
selection of catalyst and process conditions, FCC can be
LCO, vol % 26.3 17.3 operated to maximize middle distillates, gasoline, or light
Decant oil, vol % 17.8 7.9 olefins [20]. Diesel or middle-distillate mode is character-
ized by lower operational severity with milder temperature
Sulfur in products and catalyst-to-oil ratios. In this mode of operation, to
Gasoline 0.303 0.002 maximize the bottoms conversion, recycling of heavy cycle
LCO 2.38 0.09
oil is usually practiced. Intermediate temperatures, higher
Decant oil 3.25 0.23
SOx emission, kg/m3 of feed 1.3 0.09
catalyst-to-oil ratios, and higher catalyst activity are associ-
ated with the gasoline mode of operation. In light olefins
or the LPG mode of operation, reactor temperatures are
Although FCC feed hydrotreatment offers excellent usually maintained above 540°C and higher catalyst-to-oil
benefits in the form of improved product quality and ratios are preferred. The liquid products in this mode are
yields, excessive treatment beyond the optimum does not highly aromatic, and in some units the propylene yield
always correspond with higher gasoline yields. A study by could be as high as 20 % [21,22]. Table 6.4A presents the
UOP [19] suggests that the optimal feed hydrogen content typical operating conditions and product yields obtained
should be between 12.3 and 12.5 wt %. Beyond this, more with a Middle Eastern VGO.

Table 6.4a—Operating Conditions, Product Yields, and Properties with

Different Modes of FCC Operation [20]
Middle Distillate Mode Gasoline Mode Light Olefins Mode

Operating conditions
Temperature (°C) 449–510 527–538 538–560
Catalyst to oil <Base Base >Base
Recycle, CFR 1.4 (HCO) optional (HDT LCO) optional (HN)

Product yields
H2S wt % 0.7 1.0 1.0
C2-, wt % 2.6 3.2 4.7
C3, LV % 6.9 10.7 16.1
C4, LV % 9.8 15.4 20.5
C5+ gasoline, LV % 43.4 60.0 55.2
LCO, LV % 37.5 13.9 10.1
HCO, LV % 7.6 9.2 7.0
Coke, wt % 4.9 5.0 6.4

Product properties

LPG, vol/vol
C3 olefins/saturates 3.4 3.2 3.6
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

C4 olefins/saturates 1.6 1.8 2.1

Gasoline
ASTM 90 % point, °C 193 193 193
ASTM 90 % point, °F 380 380 380
Research octane number clear (RONC) 90.5 93.2 94.8
Motor octane number clear (MONC) 78.8 80.4 82.1
LCO
ASTM 90 % point, °C 350 316 316
ASTM 90 % point, °F 670 600 600
Flash point °C (°F) 97 (207) 97 (207) 97 (207)
Viscosity, cSt at 500 °C (1220°F) 3.7 3.1 3.2
Sulfur, wt % 2.9 3.4 3.7
Cetane index 34.3 24.3 20.6

Clarified oil
Viscosity, cSt at 1000°C (2100°F) 10.9 9.0 10.1
Sulfur, wt % 5.1 6.0 6.8

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AST-MNL58-11-0801-006.indd 134 3/12/13 2:01 PM

Chapter 6 n Fluid Catalytic Cracking 135

Table 6.4b—Operating Conditions and 6.7 Commercial FCC Designs

Subsequent to the first commercial operation of an FCC
Product Yields with Two Different Modes of
unit in 1942, the original design has undergone several
DCC Operation [23]
changes. Availability of highly active catalysts, demand for
Type I Type II higher feed capacities, improved yields, product selectivity,
Operating conditions
changes in feed quality, operational ease, reliability, and
Temperature (oC) 530–575 505–555 longer cycle lengths are some of the key drivers for these
Catalyst to oil (w/w) 8–15 7–12 changes. Nevertheless, in all of these designs, the basic
Steam dilution rate, wt % of feed 20–30 10–15 function of the FCC components such as reactor, stripper,
Type of cracking Riser and bed Riser regenerator, and transfer lines, etc., remain the same.
Among the new designs, the most popular ones are
Material balance, wt %
C2- 11.9 5.6
UOP’s side-by-side configuration, KBR’s Orthoflow™, Exx-
C3 and C4 LPG 42.2 34.5 on’s flexicracker unit, Shaw/Axens’s two-stage regeneration
Naphtha 26.6 39.0 unit, etc. Figures 6.8 and 6.9 present the schematics of
LCO 6.6 9.8 some of these designs. Each of these designs incorpo-
DO 6.1 5.8 rates their proprietary know-how and brings in their own
Coke 6.0 4.3 strengths and weaknesses. Nevertheless, there have been
Loss 0.6 1.0 many engineering advancements in these designs from the
Total 100.0 100.0 point of view of basic reaction engineering, heat and mass
Light olefin yield, wt % transfer, and fluid mechanics. Some of the recent develop-
Ethylene 6.1 2.3 ments include high-efficiency feed nozzles for improved
Propylene 21.0 14.3 feed vaporization, short contact time reactors for better
Butylene 14.3 14.7 yield and selectivities, catalyst coolers and riser quench
In which isobutylene 5.1 6.1 for handling excess heat with residue feedstocks, two-stage
Amylene – 9.8 regenerators for reduced deactivation and improved regen-
In which isoamylene – 6.8 eration, improved stand pipe design/operation for higher
Feed: waxy Chinese VGO pilot plant data catalyst circulation, etc. [21,22,24,25,27–29]. The following
sections cover some of these engineering and design aspects

Over the past few years, the light-olefin mode of opera-

tion has gained major importance because of the growing
demand for propylene. The key advantages of producing
propylene through the FCC route are the higher ratio of
propylene-to-ethylene yields and relatively less severe oper-
ating conditions compared with steam cracking. Almost
all major licensors offer light-olefin production technology
through their patented processes [21,22,24,25]. Table 6.4B
presents the yields and operating conditions with the two
different modes of deep catalytic cracking (DCC) opera-
tion of Shaw through maximum propylene or high-severity
operation (type I) and maximum iso-olefin or lower sever-
ity operation (type II) [23]. Because a significant amount
of ethylene is also produced in olefin mode, the option of
Exxon Flexicracker Exxon Model IV
recovering ethylene is worth examining.
FCC LPG is a rich source for other light olefins such
as butylenes and amylene and hence is an ideal feedstock
for methyl tertiary butyl ether (MTBE)/tert-amyl methyl
ether (TAME) or alkylation. The ratio of isobutylene to
total butylenes is much higher in olefin-mode operation
compared with gasoline mode. Because of the high conver-
sion, all of the C5+ liquid products are highly aromatic and
the naphtha is octane rich. The BTX content of the naphtha
is over 25 wt %, making it suitable for extraction [26]. The
di-olefins in naphtha need to be selectively hydrotreated to
improve its stability. The cycle oil from FCC, particularly
in olefin mode, is low in cetane and hence it needs further
upgradation for blending in a diesel pool. Alternatively, it
can be used as an excellent cutter stock because of its low
UOP High Efficiency
viscosity and pour point. The heavy cycle oil (HCO) and UOP Side by Side Regenerator
small amounts of slurry oil can go directly to fuel oil blend-
ing, or the slurry oil can be used as carbon black feedstock
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- Figure 6.8—Some commercial FCC configurations. Source:
(CBFS). Reproduced with permission from Exxon Mobil and UOP.
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136 Petroleum Refining and Natural Gas Processing

To flue gas
treatment
Closed
cyclone
system
To M.F. &
gas plant
Multi-stage
stripper Quench
2nd stage
regenerator
Riser separation
system: RS2

Air Stripper internals

Stripping steam
Spent catalyst
distributor
1st stage
regenerator
Pipe grid MTC
ATOMAX air
feed distributor Feed
injection
Air
Lift air
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 6.9—KBR FCC configuration (courtesy KBR Inc.) (left) and Shaw & Axens configuration (right). Source: Reprinted with
permission from Hydrocarbon Processing, by Gulf Publishing Co., © 2005; all rights reserved.

in detail. Useful guidelines for FCC hardware design are Higher slip factors would lead to higher catalyst hold
given in Table 6.5. up and hence coke make. In straight FCC risers the slip fac-
tors typically range from 1.5 to 2. The slip factors are high
6.7.1 FCC Riser in the feed vaporization zone in various bends, slopes, and
It is well known from basic reaction engineering principles curves. When operating conditions are not widely different,
that to maximize intermediates, plug flow configuration is lower catalyst-to-oil ratios give lower slip factors.
the optimal choice [30]. VGO cracking reactions being con- Curves and bends promote uneven distribution of cata-
secutive, the plug flow scheme is ideal for maximal yields of lyst, poor oil contact across the horizontal cross section,
gasoline at a given conversion. Back-mixing of the gasoline and catalyst maldistribution to the riser termination device.
leads to higher LPG yields because of overcracking. For- In FCC, the base of the wye section is highly turbulent as
tunately, the advent of highly active zeolite catalysts also the regenerator catalyst flow changes its direction. There-
helped in moving toward dilute phase, plug flow, all-riser fore, elevated nozzles are recommended so that the liquid
cracking from early dense bed cracking. spray can come in contact with the hot catalyst, the radial
Catalyst residence time, which depends on catalyst density profile of which is uniform. Modern FCC units are
hold up and circulation rates, is another important factor designed for all-riser cracking with reduced back-mixing.
in FCC design. Lower catalyst residence times are preferred This is accomplished through efficient feed injection and
because they produce substantially reduced coke make for vaporization at the riser entry zone and rapid separation
a given hydrocarbon flow [8,31]. In plug flow reactors, the of catalyst and product at the riser exit. The all-riser crack-
catalyst hold up time is dependent on slip factor (ratio of ing maximizes the gasoline yield and eliminates secondary
gas to catalyst velocity). The following equation can be dilute-phase cracking and postriser thermal cracking. Short
used for estimating catalyst hold up in any section of the contact time reactors with all-riser cracking and cracking
riser [4]: temperatures above 530°C are now common to produce
high-octane gasoline and light olefins [32].
(CCR)(SF ) dL
dH = (6.14)
60V
6.7.2 Feed Nozzles
where: An efficient feed injection system helps in the rapid vapor-
H = catalyst hold up (t), ization of feed and simultaneously quenches the hot regen-
CCR = catalyst circulation rate (t/min), erated catalyst. Faster feed vaporization results in reduced
SF = slip factor, liquid-phase cracking, hot spots, catalyst slip, and back-
L = length (m), and mixing, leading to less coke and dry gas make [33]. In an
V = vapor velocity (m/s). ideal scenario, the cracking should only take place in the
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Chapter 6 n Fluid Catalytic Cracking 137

Table 6.5—Useful Guidelines for FCC Hardware Design [34]

Stand pipe • Minimum catalyst flux: 100 lb/ft2·s
• Maximum catalyst flux: 300 lb/ft2·s
• Typical flux: 150–250 lb/ft2·s
• Orientation: Vertical or not more than 35° to vertical
• Aeration: 20–25 SCF/t of catalyst per 100-ft vertical drop

Controlling catalyst • 2 psi minimum for control

slide valve • 15 psi maximum for wear
• 25–75 % open for control
• Design for ~7 psi and 50 % open
• Slide valve port area ~0.25–0.45 of stand pipe area

Riser • Minimum velocity for vertical spent catalyst riser: 8–10 ft/s
• Minimum velocity for vertical feed riser: 15–20 ft/s (at bottom)
• Maximum riser velocity: 90 ft/s (for wear)
• Typical feed riser exit velocity: 50–70 ft/s
• Feed riser residence time: 1.8–2.4 s (based on outlet moles)
• Feed riser L/D: at least 20 preferred
• Feed riser turndowns: 80–95 % separation efficiency

Feed nozzle • L/D : 3–10

• Steam flow rate: 3–5 wt % of feed (depends on feed properties)
• Nozzle tip: depends on type of feed distribution and yield pattern required (generally pattern of distribution
is hollow cones or flat sprays)

Reactor vessels • Maximum operating velocity: 3.5 ft/s (with efficient cyclones)
• Typical operating velocities: 2–3 ft/s
• Disengaging height (riser turndown to cyclone inlet): 15 ft minimum

Stripper • Superficial steam velocity: 0.5–1 ft/s

• Typical steam rates: 2-4 lb of steam per 1000 lb of catalyst
• Typical operating velocities: 0.5–1 ft/s
• Typical catalyst residence time: 60–90 s
• Typical catalyst flux: 1200 lb/ft2·min
• Stripper L/D: at least 1
• Free area between baffles: 45–55 % of stripper area
• Unbaffled strippers not recommended if stripper steam efficiency a concern

Regenerator vessels • Maximum operating velocity: 3.3 ft/s

• Typical operating velocity: 2-3 ft/s
• 3.5–5.5 ft/s(UOP high efficiency)
• Catalyst residence time: 5–10 min (one-stage regeneration)
• 1 min (UOP high efficiency)
• 3–5 min (each stage is two-stage design)
• Bed L/D: 0.3–0.7 in conventional designs
• Disengaging height: 18–20 ft (bed surface cyclone inlet in conventional design)
• Grid pressure drop: typical 1–2 psi, at least 30 % bed head
• Minimum grid pressure drop: 0.7–0.8 psi

Cyclones • Reactor 1 stage design: typical collection efficiency: 99.995 %

• Typical pressure drop: 0.5–0.7 psi
• Inlet catalyst loading ~0.25–0.5 lb/ft3
• Regenerator 2 stage design: typical overall collection efficiency: 99.998 %
• Typical pressure drop: 1 psi
• Inlet velocities (ft/s):
• Riser cyclones: 60–70
• Reactor cyclones: 60–80
• Regenerator first stage 60–80
• Regenerator second stage 75–85
• Outlet velocities (ft/s):
• Riser cyclones: 70–80
• Reactor cyclones: 80–100
• Regenerator first stage 70–80
• Regenerator second stage 100–200
• Dipleg mass velocities (lb/ft2·s): 120–130

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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AST-MNL58-11-0801-006.indd 137 3/12/13 2:02 PM

138 Petroleum Refining and Natural Gas Processing

(a) (c)

Steam
Expansion

Oil

ATOMAX-2
Steam Multi-slotted

Oil inlet

Steam
inlet

(b)
Target bolt

Figure 6.10—Schematic of FCC nozzles [Kellogg (a), Shaw (b)] and their arrangement in riser (c). ATOMAX is a trademark of
M.W. Kellogg. Source: Figure used courtesy of KBR Inc., and Axens and Shaw.

vapor phase, and modern nozzles attempt to achieve this atmosphere while processing heavy feeds. In this scheme,
target. In these nozzles, oil is atomized into fine droplets the riser is separated into two zones where a part of the
of narrow size distribution and then distributed uniformly fresh feed or quench stream is injected at higher elevation
over the riser cross section for intimate contact with the so that high mix zone temperature and catalyst-to-oil ratio
catalyst. The key liquid-phase variables that affect the are achieved at the bottom. Such designs allow independent
vaporization are droplet size, liquid flux and spray pattern, control of mix temperature without any metallurgical con-
and penetration into the flowing catalyst. Catalyst-phase straints from the reactor [29]. Riser quench acts as a heat
variables include temperature, velocity, density, and sink and is similar to a catalyst cooler; however, it increases
distribution [2]. load on the downstream section.
FCC nozzles are designed, through extensive cold flow
testing, to produce a flat fan spray pattern of liquid feed 6.7.3 Riser Termination Device
distribution with small droplets of narrow size. Figure 6.10 Disengaging designs were previously used to separate
shows the schematics of a few commercially available FCC the riser product stream from the spent catalyst through
feed nozzles. inertial separation devices or rough-cut cyclones. The key
In Shaw/Axens’s feed injectors, the oil inlet orifice disadvantages of such systems were longer hydrocarbon
directs a high-velocity jet of oil onto a target bolt. Steam residence time in the dilute phase and higher back-mixing,
enters the nozzle at high velocity and shears the oil droplets thus promoting undesirable secondary cracking reactions
formed on the target. It is claimed that the oil then fila- and thermal cracking, leading to higher coke and gas make.
ments and further atomizes as it passes down the barrel of However, some key advantages of such designs were opera-
the nozzle and is then shaped into a fan spray pattern at the tional simplicity and the absence of dead pockets, which
tip. The optimal use of atomization steam and feed oil pres- prevents coke formation on reactor walls, etc. [35]. Modern
sure drop to achieve fine atomization depends on the type riser termination devices ensure smooth separation of the
of feedstock. In Kellogg’s atomization nozzle ATOMAX™, catalyst from the product stream without disturbing the
most of the mixing energy comes from medium-pressure plug flow to a great extent and directing hydrocarbons
steam. Likewise, the Lummus Micro-Jet™ and UOP Opti- more efficiently toward the reactor plenum, thus producing
mix™ also uses steam energy for shearing the oil and atomi- less coke and gas make, as shown in Figure 6.11 [36].
zation [14]. It was suggested that atomization closer to the The close coupled cyclones of Lummus and Kellogg,
nozzle tip is important for flat plane contacting and reduced the Vortex Separation System (VSS™) of UOP, and the
re-coalescence. An improved mixing chamber through pro- Riser Separation System or RS²SM design of Axens and
prietary internals, tip design, and nozzle orientation are key Shaw are some of the new disengaging devices. In close
technology aspects. Lower oil-side pressure drop and the coupled systems, the catalyst and hydrocarbons enter
independent control of steam flow are claimed to be some directly into the cyclone and the hydrocarbons are effi-
of the advantages of these nozzles. The typical steam disper- ciently separated from the spent catalyst, thus drastically
sion rates reported for Optimix nozzles were 1–2 wt %, and reducing the hydrocarbon leakage into the dilute phase
the pressure drops range from 30 to 60 psi [2]. (Figure 6.12). The cyclone can operate under positive or
To uniformly cover the riser radial cross section, multi- negative pressure relativeto the reactor free board pressure (i.e.,
ple feed nozzles are used. Further segregated feed injection dilute bed). The close coupled cyclones can reduce the hydro-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`-

systems are also practiced to create a more severe cracking carbon residence time to as low as 2 s. The negative pressure
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Chapter 6 n Fluid Catalytic Cracking 139

Inertial Separator Riser Cyclones Closed Cyclones

Figure 6.11—Evolution of riser termination designs. Source: Figure used courtesy of KBR, Inc.

(a) (b)

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
(c)

Figure 6.12—Schematic of FCC riser termination designs: (a) VSS (UOP), (b) RS2 (Shaw). (Source: Used with permission of UOP and
Shaw), and (c) close-coupled cyclones [37].
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140 Petroleum Refining and Natural Gas Processing

s ystems minimize the hydrocarbon seepage through pri- e fficient diffusion of hydrocarbons from catalyst pores into
mary cyclone diplegs. Although advantageous, the close the upflowing steam. In unbaffled strippers, catalyst segre-
coupled systems are thought to be susceptible to upsets and gates toward the walls whereas steam flows exclusively in
can lead to catalyst carryover to the main fractionator [35]. the center, leading to poor stripping. The baffled strippers
The VSS™ and RS²SM designs are claimed to be less force the two phases to flow in truly countercurrent fashion
susceptible to upsets with enclosed separation of hydro- with reduced back-mixing. Papa and Zenz [38] proposed a
carbons. These designs attempt to provide operational design criterion for strippers following the analogy of sepa-
ease while simultaneously reducing the hydrocarbon resi- ration units. According to this criterion, to achieve true
dence time. Using the momentum, most hydrocarbons are countercurrent plug flow for both of the phases requires
separated from the spent catalyst and directed toward the operating the unit at approximately 75–80% of flooding
cyclones through proprietary designs. The separated cata- flow rates. The maximal flooding flow rate of either phase
lyst is prestripped in an enclosed chamber to minimize the can be estimated from the following relation [38,39]:
hydrocarbon release, thus attaining higher levels of hydro- 2
carbon containment.  ( ACFM / A) 40.5  3
 ( Bulk CFM / A ) 40.5 
  = 43.86 – 0.794  
 ( ∆ρ / ρ )0.5 D 0.5   ( ∆ρ / ρ D ) D
0.5 0.5

6.7.4 Stripper Internals  g 
FCC catalyst that is separated from the riser contains a
significant amount of hydrocarbons in the pores and inter- (6.15)
stitial voids. The entrapped hydrocarbons are separated by
displacement with steam in the stripping section, which where:
otherwise would land in the regenerator, increasing the ACFM = actual gas flow rate (ft3/min),
combustion load. Steam is typically introduced through Bulk CFM = catalyst flow rate (ft3/min),
two steam distributors. Most of the volatile light hydro- A = total area of the slot or hole (ft2),
carbons will be removed through prestripping steam intro- D = width of slot or diameter of hole (ft),
duced in the upper stripper bed. The prestripped catalyst ρg = gas-phase density (lb/ft3),
flows down through a series of baffles such as disk and ρD = catalyst bulk density (lb/ft3), and
donuts, sheds, tube bundles, etc., against a countercurrent Δρ = ρD – ρg (lb/ft3).
stripping steam (Figure 6.13). The effect of pressure due to static head can be
The baffles arrangement improves the catalyst steam accounted for through a similar equation [40]. Under
contact and catalyst residence time, leading to more steady-state conditions, the pressure drop across each

Figure 6.13—Various types of stripper baffles (Chevron grids, disk and donut, tube bundles) (top) and flow areas and diameters
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

as defined in stripper performance equations (bottom). Source: Reprinted with permission from [38].
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Chapter 6 n Fluid Catalytic Cracking 141

baffle is expected to be the same for constant catalyst flux. where:

The back-mixing can be reduced through closer baffle spac- Q = aeration required to prevent defluidization (m3/s);
ing. However, there is a penalty on capacity due to reduced Pb and Pt = pressures at the bottom and top of the stand
head. Another parameter that influences stripper efficiency pipe, respectively (Pa);
is the length to diameter (L/D) ratio. Strippers with larger ρmf and ρt = fluid bed density at minimum fluidization veloc-
L/D ratios are observed to give higher efficiency because of ity and at top of stand pipe, respectively (kg/m3); and
lower effective diameter. ρsk = skeletal density (kg/m3).
Hydrogen content in the coke fraction of spent catalyst, Catalyst fines play an important role in promoting
referred to as “hydrogen in coke,” is often considered as an catalyst circulation by improving the fluidity [45]. The ratio
indication of stripper efficiency. Because the hard coke on of minimum bubbling (Umb) to minimum fluidization (Umf)
spent catalyst is expected to contain much less hydrogen velocities, which is a strong function of fines content, is
compared with the hydrogen content of the volatile mate- given below [46]. The higher ratio indicates a larger oper-
rial (soft coke), this parameter is easily distinguishable and ating window for stand pipe operation and a less frequent
is hence widely followed. In industry, a value less than 7 % aeration requirement.
is considered to be good whereas 6 % is ideal [14,41]. Nev-
ertheless, the hydrogen in coke depends on other factors

Umb
= 2300
(ρ0g.126µ0.523 e0.716 F 45 ) (6.17)
such as stripper temperature, catalyst, type of feed being
(
dp0.8 ( ρ p – ρ g ) g )
0.934
Umf
processed, etc. Generally, catalysts with small pore diam-
eter (high surface area and low pore volume) require more
steaming and residence time due to poor “strippability” of where:
heavier molecules. Higher stripper temperatures are likely ρg = gas density (kg/m3),
to help in desorbing these compounds efficiently due to μ = gas viscosity (kg/m·s),
improved volatilization and/or further cracking [42]. F45 = fraction of fines < 45 μm,
Typically, 2–5 kg of stripping steam is used for every dp = mean particle size,
ton of circulating catalyst; needless to say the optimal ρp = particle density, and
value depends on catalyst, feed, and operating parameters. g = gravitational constant.
Often refiners optimize the steam flow rates on the basis of
regenerator temperature. Up to a point, an increase in strip- 6.7.5 Regenerator
ping steam reduces the regenerator temperature; beyond An FCC regenerator design is decided primarily based on
optimum, the reduction in coke content would be minimal. the coke burning capacity and catalyst circulation rates. In
most situations, single-stage regeneration with or without
catalyst cooler may be adequate. For handling high-CCR
6.7.4.1 Stand Pipes feeds, two-stage configuration or two stages with catalyst
Stand pipes are circular pipes for the transportation of solids cooler are required. Occasionally, single-stage regenera-
from one section of the unit to another. These can be verti- tors are also used in partial combustion mode while pro-
cal, angled, or a combination of these two. The two primary cessing moderate CCR feeds so that the heat release is
stand pipes in FCC units are spent catalyst transfer line and restricted.
the regenerator transfer line. In these stand pipes, the solids Single-stage regenerators are typically bubbling fluid-
flow against a positive pressure differential, using the grav- ized beds where the gas superficial velocities are in the
ity head generated by the fluidizing solids, whereas the fluid- range 0.5–1 m/s. There is a distinguishable dense catalyst
izing gas flows upward relative to the solids. The stand pipes bed and a dilute phase in these regenerators. In the dilute
are typically designed in such a way that they generate more bed, the entrained catalyst travels along with the flue
pressure than required so that excess pressure can be wasted gases into the cyclones. The design velocities are decided
across the valves to maintain the pressure balance in the by optimizing the regenerator diameter and the catalyst
unit. The slide valves generally operate with a pressure drop entrainment. To keep the cyclone loading to a minimum,
of 15–100 kPa with valve opening between 25 and 75 % [43]. the regenerator height should be more than the transport
It is desirable to have vertical standpipes. In verti- disengagement height (TDH).

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
cal standpipes the pressure build-up is high, and hence Most coke burning reactions occur in a dense bed, but
higher solid fluxes are possible [44]. When the gas flow is a small fraction of CO escaping from the bed can react
below minimum fluidization, the solids cannot exert the with residual O2 in the dilute phase, leading to a slight
pressure at the base of the stand pipe as solids loose their temperature rise. In partial combustion units the differ-
fluidity, leading to reduced flow [45]. Likewise, overaera- ence between the dense and dilute bed temperatures,
tion leads to excessive interstitial void volume and hence often referred to as ”afterburn,” could be as high as 20°C,
reduced pressure. The stand pipes should ideally be oper- whereas in full combustion units this value is normally less
ated around incipient bubbling and incipient buoyancy. than 10°C. The catalyst entry and its distribution and with-
Aeration taps are usually provided uniformly along the drawal are important for achieving good regeneration and
length of the stand pipe to keep the solids in a fluidized uniform radial distribution. Figure 6.14 shows the catalyst
state and avoid large bubbles. The amount of aeration distributor system of KBR Technology.
required to maintain the solids in a fluidized state can be In the Kellogg Orthoflow™ FCC regeneration con-
computed using the following equation [44]: figuration, the spent catalyst is introduced at the top of
the dense catalyst bed and distributed uniformly through a
P  1 1  1 1 
Q = 1000  b   –  –  –  (6.16) specially designed spent catalyst distributor, whereas air is
P  ρ ρ ρ ρ
 t   mf sk   t sk  introduced from the bottom so that catalyst and air flow in
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142 Petroleum Refining and Natural Gas Processing

Two-stage regenerator designs are licensed by UOP

and Total (jointly by Stone and Webster and IFP). In the
two-stage regeneration, nearly 50–70 % of the coke is
burned in the first stage under partial combustion mode
whereas the remainder is burned under full combustion in
the second stage. The first stage operates under milder par-
tial combustion conditions (620–690°C) with deficit oxygen
atmosphere while the second stage is under excess O2 with
temperatures ranging from 670 to 760°C. In the UOP unit,
the first stage is located on top of the second stage. The
catalyst flows from the top through a stand pipe into the
second stage. The second-stage flue gas enters into the bot-
tom of the first stage so that the excess air is consumed dur-
ing the first-stage regeneration. Therefore, the combined
flue gases leave from the first stage through a single line. In
contrast, in the Stone and Webster-IFP unit the catalyst is
lifted from the first stage to the second stage using lift air.
The flue gases from the first stage should not be combined
until they are sufficiently cooled to prevent ignition.
While processing resid feeds, regenerators are often
Figure 6.14—Schematic of spent catalyst distributor and air designed with catalyst coolers. Catalyst coolers are essen-
distributors in KBR’s FCC regenerator. Source: Figure used
tially heat exchangers and act as a sink for rejecting excess
courtesy of KBR, Inc.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
heat from coke combustion (Figure 6.15). In these heat
exchangers the catalyst flows in the shell side whereas
a countercurrent manner. Countercurrent flow avoids the water and steam flow through bayonet tubes. The heat
spent catalyst coming in direct contact with fresh air, thus removal is controlled by catalyst circulation and through
preventing high particle temperature and catalyst deactiva- fluidization rates [35]. According to Letzsch (2003b), single-
tion. Likewise, because of the low O2 content at the spent stage regenerators in full combustion mode can handle feed
catalyst entry, the NOx produced in the bed is expected to CCRs of 2.5 wt %; in partial combustion the CCR can be as
react with coke, leading to reduced NOx in the flue gas. high as 3.5 % [27]. Two-stage regenerators can handle 6 %
The UOP high-efficiency regenerator operates in a fast feed CCR. With catalyst coolers, the suggested CCR limit for
fluidized bed mode with complete coke combustion. The both units is 10 %. Ultimately, issues such as overall eco-
spent catalyst enters the bottom of the combustion cham- nomics, operational flexibility, catalyst consumption, etc.,
ber and flows upward along with the air in a combustion are the key factors for the regenerator design.
riser. The high velocities and low catalyst densities promote
the combustion and significantly reduce the regeneration 6.7.6 Air Grid
time. The regenerated catalyst is collected in the upper The air grid is important hardware in an FCC regen-
containment vessel from the combustion riser through erator because it ensures good fluidization characteristics.
cyclones. Hot catalyst from this section is recycled to the Improper fluidization results in dense bed instability, lead-
bottom combustion section to preheat the spent catalyst ing to inefficient air catalyst contact, poor combustion,
for accelerated combustion. The key advantages claimed catalyst attrition, particulate entrainment, uneven cyclone
for this design are a smaller regenerator, reduced catalyst loadings, erosion, etc. Perforated plate grids, concentric
inventory, complete coke combustion, etc. rings, and pipe grids are the typical grid designs used in

Water in

Catalyst in Tubesheet

Inner
tube Water &
steam out

Tubesheet

Fluidization
Catalyst air
return Scabbard --
outer tube
Slide
valve

Figure 6.15—KBR’s dense-phase catalyst cooler arrangement. Source: Figure used courtesy of KBR, Inc.
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Chapter 6 n Fluid Catalytic Cracking 143

a b c d

Figure 6.16—Sectional view of typical FCC air grid arrangements: (a) single central pipe, (b) double central pipe, (c) tuning fork,
(d) ring-type distributors. Source: Reproduced with permission from [47].

FCC regenerators. Pipe grids are usually preferred because therefore reduces particle attrition. To be effective, shrouds
of several advantages such as low-pressure drop, minimum must be long enough to contain the expanding (11° included
weeping, good turndown ratio, and other thermal and angle) gas jet leaving the grid orifice (Figure 6.17).
mechanical advantages. Several air grid arrangements such
as single and double central pipe grids, tuning fork design, 6.7.7 Cyclones
and concentric sparger rings are available for commercial Cyclones are used for separating solid particles from a gas
FCC catalyst regenerators. Figure 6.16 shows the schematic stream using the centrifugal forces. The dust-laden gas
of some of these designs. stream enters tangentially into the cyclone at very high
Ideally, the gas distributes uniformly and covers the velocity. The centrifugal forces imparted on the solid parti-
entire cross section. This is achieved by providing adequate cles drive them toward the cyclone barrel wall, from where
grid pressure drop so that all of the grid holes discharge the particles slide down through the conical section into the
evenly. However, on the other hand, excessive pressure dipleg, ultimately landing in the catalyst bed. The spiraling
drops result in high grid hole velocities, leading to catalyst gas separated from the solids exits from the top.
attrition. The particle collection efficiency is related to the time
The grid pressure drop is a function of gas flow rate, necessary for a particle to reach the barrel wall according to
which can be estimated from the grid hole velocity [45]): Stokes’ settling velocity within the residence time available
for carrier gas. The residence time depends on the number
2∆P of spiral traverses (Ns) within the barrel, whereas Stokes’
V0 = 0.8 (6.18) velocity is a function of centrifugal force and particle prop-
ρ
erties. The minimum smallest theoretical particle (Dth) that
can cross the cyclone width within the available residence
where: time can be estimated from the following equations:
V0 = velocity through the grid hole (m/s),
Dth = [ 9 Lwµ G / πNS Vi (ρ P – ρG )] 2
1
ΔP = Pressure drop (N/m2), and
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

(6.19)
ρ = fluid density (kg/m3).
For uniform gas distribution, the following consider-
ations are important [40,45,47]: NS VI1.5 = 2.908 (6.20)
• At least 10 nozzles per square metre area to minimize
stagnation zones. where:
• A minimum of 30 % of bed pressure drop is required LW = cyclone’s inlet duct width,
across the distributor when nozzles are pointed upward, μG = gas viscosity,
whereas the minimum is 10 % with downward-pointed Vi = gas inlet velocity,
nozzles. ρp = apparent particle density, and
• Dhead2/NhDh2 should be greater than 2.5 for the manifold ρG = gas density.
flow variations and pressure drop requirements to be It is preferable to have an inlet duct with a height-
within acceptable limits (Dhead is the header pipe diam- to-width ratio (h/Lw) greater than 1 for maximizing the
eter and Nh and Dh are the number of grid holes and number of particles closer to the wall and their efficient
grid hole diameter, respectively). collection, whereas the travel distance (Lw) for settling is
A minimum grid hole pitch is to be maintained to avoid small. The collection efficiency of the particle with size
coalescence of air bubbles at the grid level. Zenz [48] sug- Dth and other fractions can be estimated from the cor-
gested that the initial bubble size is approximately half of relations. The collection efficiency increases with dust
the jet penetration length. There exists around each rising loading, and correction needs to be applied to account for
bubble a down-flowing shell of solids for which the outer the “plowing effect” of the larger particles (Figure 6.18).
periphery is concentric with the bubble such that the solids The efficiency correlations available in the literature dif-
shell diameter is 1.5 DB. To avoid premature bubble growth fer significantly because they have been developed with
by a merger of two bubbles simultaneously leaving the grid, widely differing geometries, particle properties, loadings,
the grid hole pitch should not be closer than ½ DB. Port etc. Nevertheless, the mechanistic procedure is simple and
shrouding can be used to reduce the grid hole velocity to pre- effective for new designs and troubleshooting operational
vent jet merging as well as to reduce particle attrition. Port problems when used in conjunction with optimal cyclone
shrouding reduces the velocity at the gas-solids interface and dimensions [49].
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144 Petroleum Refining and Natural Gas Processing

Catalyst

Orifice

Air nozzle
Gas bubble

Jet penetration

Port shrouding

Grid hole pitch

Manifold flow variations

Figure 6.17—Important pipe grid design considerations [40,48,50].

6.8 Catalysts and Additives molecules that enter the zeolite cage. A unit cell of zeolite
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Catalysts and additives play a major role in selectively con- Y contains 192 framework atomic positions occupied by
verting low-value VGO into high-value lighter and middle either Si or Al atoms. In the zeolites framework, Al cannot
distillates. FCC catalyst is a fine powder with an average have as its immediate neighbor another Al, thus resulting
particle size of 60–75 μm and a size distribution ranging in a Si/Al ratio of 1 or greater. A unit cell of synthesized
from 20 to 120 μm. The catalyst basically consists of four zeolite Y, with a Si/Al ratio of 2.5, contains 137 atoms of Si
major components: zeolite, active matrix, filler, and binder. and 55 atoms of Al. Because aluminum is in the +3 oxida-
Each of these constituents has a unique role in the over- tion state, each tetrahedra containing alumina has a net
all functioning of the catalyst, whereas zeolite is the key negative charge that is compensated for by sodium ions
component that is more active and selective for gasoline in as-synthesized zeolite. These charge-compensating ions
production. called “extra framework ions” are mobile and can be easily
exchanged with other ions such as ammonium ion. When
6.8.1 Catalyst Constituents calcined, ammonium ion decomposes, liberating ammo-
6.8.1.1 Zeolite nia, which escapes from zeolite leaving a H+ ion, which
Zeolite is mainly responsible for cracking activity. Zeolites is a Bronstead acid site. Hence, the number of acid sites
are structurally complex inorganic polymers that are based in the zeolite depends on the aluminum tetrahedra in the
on an infinitely extending three-dimensional, four-cornered framework. Zeolite acidity can be moderated by increasing
network of AlO4 and SiO4 tetrahedra. The structure can be the Si/Al molar ratio. This can be achieved either by syn-
considered to arise from the isomorphous substitution of Si thesizing zeolite with a higher Si/Al molar ratio or through
by Al in the crystal lattice of SiO2. The tetrahedra are linked postsynthesis modification of dealumination by steaming
to each other by a sharing of oxygen atoms to give rise to or chemical treatment.
three-dimensional structures containing voids and chan-
nels of molecular dimensions. 6.8.1.2 Synthesis of Zeolites
Zeolite Y, which is isostructural to Faujasite, a naturally Zeolite is generally synthesized starting from sodium
occurring zeolite having a pore opening of approximately 8 Å, silicate and sodium aluminate. The sodium ions can be
is used for manufacturing FCC catalyst. The size of the replaced partially by ion exchange with ammonium or
pore opening puts a limit on the size of the hydrocarbon rare earth ions in aqueous solutions. The presence of
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Chapter 6 n Fluid Catalytic Cracking 145

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 6.18—Cyclone performance curves. Source: Figure used with permission from [51].

sodium is detrimental to the catalyst because sodium sodium cannot be completely removed from zeolite, it
neutralizes the zeolite acidity and reduces its hydrother- can be reduced to as low as 0.2–0.3 wt % after steaming
mal stability. Both standard Y and USY can be treated followed by ion exchanges. Rare earth exchange not only
with other cations, particularly with rare earth mixture increases the activity of the zeolite but also enhances the
(mainly cerium and lanthanum), to remove sodium to resistance to deactivation. A richer rare earth content in
form REY and REUSY zeolites, respectively. Although zeolite improves the hydrothermal stability. A schematic
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146 Petroleum Refining and Natural Gas Processing

breakage of Al–O bonds, which are weaker than Si–O

Alumina precursor Silica precursor bonds, ultimately resulting in a collapse of zeolite struc-
ture. To improve the stability, manufacturers dealuminate
the zeolites in a controlled manner by steam or chemical
treatment. The dealumination process extracts aluminum
from the framework. The vacancy thus created is filled
with a silicon atom, preventing collapse of the framework
NaOH + template structure. The resulting ultrastable zeolite Y (USY) is more
resistant to deactivation in the FCC than its parent standard
Y because the lower framework aluminum content in USY
NaY, 13%Na2O,UCS = 24.68 reduces the thermodynamic driving force for expelling
additional aluminum at FCC unit operating conditions.
Further, the sodium level in USY is generally lower because
Ammonium ion exchange of the dealumination process, which also gives higher resis-
tance to deactivation. Steaming or hydrothermal pretreat-
NHY, 3% Na2O ment is a preferred option over chemical treatment for the
production of USY zeolite. During this process mesopores
in the range of 30–60 Å are formed when a small portion of
Steam calcination aluminum is not replaced by silicon. The increased porosity
enhances hydrocarbon diffusion.
USY, 3% Na2O The catalyst activity mainly depends on the zeolite
UCS, ~24.50 acidity, which in turn depends on the Si/Al ratio. The zeolite
Si/Al ratio can be determined by measuring unit cell size
Figure 6.19—Schematic of synthesis of USY zeolite [41]. (UCS) by X-ray powder diffraction. Because the Al atom is
larger than the Si atom, the UCS decreases with an increase
in the Si/Al atomic ratio. Hence, the lower the UCS, the
of commercial synthesis of the Y zeolite and exchanged lower is the aluminum content and acid density. The UCS of
zeolites is represented in Figure 6.19. USY is always lower than that of standard zeolite because
Higher zeolite acid site density favors increased hydro- the former contains less aluminum atoms per unit cell. For
gen transfer, resulting in more paraffin formation. The example, a standard fresh zeolite Y with a UCS of 24.93
presence of higher paraffins in gasoline leads to lower Å contains 85 Al atoms per unit cell, and a USY zeolite
octane. Because paraffins are more stable than olefins, with a UCS of 24.25 Å contains 34 Al atoms per unit cell.
they undergo less consecutive cracking themselves. Hence, Therefore, USY is less acidic than standard Y zeolite. The
REY catalyst with higher acid site density (higher alu- structure of Y zeolite and other FCC catalyst constituents
minum content) results in poor gasoline quality but a are shown in Figure 6.21.
slight improvement in gasoline yields. However, coke yield
also increases with such catalyst as a result of increased
hydrogen transfer reactions. Loss of hydrogen from heavy 6.8.1.4 Active Matrix
aromatics increases their coke-forming tendency. The influ- The active matrix is one of the most important constituents
ence of rare earth content on zeolite unit cell parameter is in FCC catalysts and possesses cracking activity, other than
explained in Figure 6.20. the zeolite. The main function of the matrix is to pre-crack
the molecules that are too large to enter the micropores
6.8.1.3 Stability of Zeolite of zeolite, thereby contributing significantly to the overall
Zeolite is subjected to severe hydrothermal conditions performance of the FCC catalyst. However, matrices are
in FCC units during catalyst regeneration. This leads to not as selective as zeolites. Active matrix material such as

24.5 Alumina rich zeolite

24.45 High acid site density
High hydrogen
24.4 transfer (HT)
Alumina
UCS (A )
0

24.35
poor zeolite,
24.3 Low acidity
24.25
24.2
24.15
0 2 4 6 8 10 12 14 16 18
Rare earth content in the zeolite, RE2O3,
Si/Al ratio

Figure 6.20—Influence of rare earth content on zeolite UCS parameter [52].

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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Chapter 6 n Fluid Catalytic Cracking 147

Figure 6.21—FCC catalyst constituents. Source: Figure used courtesy of Intercat, Inc.

lumina or silica-alumina used in FCC catalysts is mostly

a as alumina polymers and clay-based binders may have bot-
amorphous in nature. However, the active matrices consist toms cracking activity. The binder plays a predominant role
of large pores in the mesopore (20–500 Å) and macropore in enhancing the mechanical strength, especially when FCC
(>500 Å) range. The large pores provide access to heavier catalyst contains more zeolite [53].
hydrocarbons present in the FCC feed, resulting in higher The combined role of filler and binder is to provide
bottoms cracking. The degree of bottoms conversion can be physical strength, heat transfer media, and particle size
adjusted by varying the amounts of active matrix and zeo- distribution as well as to improve fluidization behavior. In
lite in a catalyst. The active matrix activity and selectivity summary, zeolite is the main component of FCC catalyst
are affected by its acid site density, acid strength, and pore contributing to surface area, activity, and selectivity. The
structure. All of these aspects can be varied by the specific matrix takes care of large hydrocarbon molecules approach-
type of active matrix selected and the physical and chemical ing the zeolite. Filler and binder ensure overall strength of
treatment these materials are subjected to. Hence, differ- the catalyst. The synergetic effect of all three constituents
ent matrix materials can exhibit different cracking activity results in the desired performance of the FCC catalyst.
depending on their acid site density, acid strength, and pore
structure. Matrix surface area is one of the measures of its 6.8.2 Catalyst Design
activity. Reduction in active matrix surface area reduces its Each FCC unit is specific and needs, depending on feed
cracking activity. However, matrices are more resistant to quality, product requirement and process conditions, a
deactivation than zeolite. Active matrix also acts as a trap specifically tailored catalyst. Designing of an optimal
for some of the vanadium and basic nitrogen present in catalyst for a given situation requires a good understanding
the feed. Metals such as vanadium destroy the zeolite, but of the nature and proportions of various catalyst compo-
active matrix is less sensitive to their attack. nents. Scherzer [52] classified FCC catalysts into five main
Although the active matrix is useful for bottoms crack- domains that are shown schematically by plotting zeolite
ing, its poor selectivity limits its quantity in an FCC catalyst. UCS versus the Z/M ratio (Figure 6.22). This scheme gives a
Therefore, a proper balance between matrix and zeolite clear understanding of the requirement of different catalyst
activity needs to be maintained depending on feed type, properties for a specific application.
unit operating conditions, and product demand. The ratio While designing an FCC catalyst for resid feeds, the
of surface area of zeolite to matrix (Z/M) is one of the main parameters to be considered are catalyst pore struc-
measures of the expected performance of the catalyst. The ture, coke selectivity, and metal tolerance. Pore dimensions
Z/M of a given catalyst can be experimentally measured by must be optimized for efficient diffusion of reactants and
nitrogen adsorption. products by adjusting for the properties of the active matrix
and the zeolite component. In addition, the resid cracking
6.8.1.5 Filler and Binder catalyst should also have additional properties such as
Filler is a clay, mostly kaoline, added into an FCC catalyst to metal tolerance. Use of metal traps can increase the metal
dilute its activity. It also acts as a heat sink and heat trans- tolerance level of catalysts. Coke selectivity is another
fer medium. It can also act as a sink for sodium, thereby important parameter. An improvement in catalyst coke
improving the resistance to sodium poisoning. Filler is selectivity helps in achieving higher conversion in the FCC
mostly inert; if treated, then some acidity may be incorpo- unit. Coke yield increases with an increase in the degree
rated into it. of rare earth, whereas coke selectivity decreases with the
Binder is an important component of an FCC catalyst increase in UCS [52]. Thus, when designing FCC catalysts
because it helps in holding together all of the constituents for maximal coke selectivity, rare earth exchange in zeolite
(i.e., zeolite, active matrix, and filler). Generally, binder should be used to target moderate UCS (24.28–24.33 Å).
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

may not have catalytic activity. However, some binders such In addition, rare-earth-based vanadium traps can be
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148 Petroleum Refining and Natural Gas Processing

Low UCS • Maximum coke

• Maximum
conversion of 350C • Moderate gasoline
• Maximum LPG yield
(C3 + C4) • Moderate octane number
• Maximum octane
number
Increased octane number
Increased RE content

• Maximum octane number

• Good conversion of • Maximum gasoline

350C yield
• Minimum , LPG • Minimum octane
(C3 + C4) number
• Maximum coke • Minimum, LPG ( C3
+C4)
High CSU

Low Z/M Ratio of Z/M activities High Z/M

Increased matrix activity
Increased coke production

Figure 6.22—FCC catalyst composition corresponding to specific utilization [52].

f ormulated as a separate catalyst additive to improve coke However, use of a metal trap is a better approach when the
selectivity by trapping metals and inhibiting undesirable feed metal concentration is high. Different metal oxides or
hydrogen-forming reactions [54]. mixed oxides such as Al2O3, TiO2, BaTiO3, Ca ZrO3, and SnO2
The FCC unit bottoms cracking mechanism involves as well as natural clays have been used as metal traps. Metal
three different reaction types: precracking of large mol- traps are used in two ways. One way is to use a metal trap
ecules, dealkylation of alkyl aromatics, and conversion of as an integral part of an FCC catalyst; the other way is to
naphtheno aromatics [55]. Designing catalyst pore struc- add separately as and when required.
ture for efficient diffusion is an important consideration Antimony- or bismuth-based additives are generally
when resid feed is processed. Molecular simulation studies used as nickel passivators.
have indicated that molecules boiling in the range of 371–
570°C are approximately 10–30 Å in diameter. A diffusion
R
simulation model suggests that the pore size must be 10–20
times bigger than the actual feed molecules to overcome O S
diffusion limitations. Thus, the FCC catalyst must have P S Sb (6.22)
pore diameters of 100–600 Å to allow for the active diffu-
sion of resid molecules. Pores smaller than 100 Å result in O
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

coke and hydrogen; pores larger than 1000 Å result in high R 3

catalyst attrition.
During the cracking process, metals in FCC feedstock
are deposited on the catalyst surface leading to reduced Antimony-based additives are typically liquid additives, and
activity. Vanadium and sodium cause permanent catalyst their general formula is represented in Eq 6.22, where R is
deactivation whereas nitrogen is a temporary poison. a hydrocarbyl radical containing from 1 to approximately
Nickel promotes dehydrogenation reactions, which result 18 carbon atoms. The overall number of carbon atoms per
in higher dry gas and coke make. molecule is in the range of 6 to approximately 90, and the
Vanadium is harmful to the catalyst because in pres- nickel is passivated by forming a nickel antimony alloy
ence of steam it forms vanadic acid, which can destroy the [56,57]. Addition of antimony solution depends on the
zeolite by hydrolysis of its framework. concentration of nickel in the FCC equilibrium catalyst.
An antimony-to-nickel ratio of 0.3–0.5 is considered to be
V2O5 + 3H2O 2H3VO4 (6.21) optimum for effective nickel passivation [41].
While processing resids, iron is another metal poison.
The deleterious effects of metal can be countered If present in feed, iron can cause a loss in unit conver-
to some extent by increasing the catalyst addition rates. sion, poor catalyst circulation, lower gasoline research
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Chapter 6 n Fluid Catalytic Cracking 149

Figure 6.23—Shape selectivity of ZSM-5 [58].

octane number (RON), and SOx emissions [59–61]. Iron in the plant hardware. The additive concentration typically
contamination can lead to pore closure and nodule forma- ranges from 0.1 to 40 wt % of the base catalyst depending
tion. The effect is attributed to the reaction of iron oxides on the type of the reaction. The physicochemical properties
with silica or other metals such as sodium and calcium, of these additives closely match with the base catalyst. The
resulting in low temperature phases and collapse of the most common FCC additives are ZSM-5, gasoline sulfur
exterior surface of the catalyst particle, which decreases reduction additive, SOx reduction additive, CO combustion
the apparent bulk density. Alumina is resistant to such promoter additive, metal passivator, and NOx reduction
effects by iron. Significant improvements can be achieved additive.
by switching to high-accessibility alumina-based catalysts
while processing iron-containing feeds [60]. The alkali 6.8.3.1 ZSM-5
metals (sodium and potassium) and alkaline earths (cal- ZSM-5 belongs to the pentasil zeolite family and is primar-
cium, magnesium, and barium) are harmful to a catalyst, ily used for octane boosting or LPG maximization. It is
especially under high regenerator severity. The activity is a stable zeolite with an alumina content below 10 % and
lost because of formation of eutectics with the catalyst. pores with diameters in the range of 5.5 Ǻ . It has a dis-
Catalysts with a balanced Z/M and a high zeolite content tinctly different pore structure and pore arrangement than
with moderate rare earth exchange (UCS ≥ 24.30 Å) resist Y zeolite. Because of shape selectivity, only long-chain,
deactivation. Active matrix is also suggested to act as a low-octane-gasoline-range, normal paraffin molecules enter
sodium sink and protect zeolite [62]. To counter the tem- its pores and undergo rapid cracking (Figure 6.23) [58].
porary deactivation due to nitrogen, the catalyst should be Because of its high Si/Al (>20) ratio, use of ZSM-5 results in
formulated with high zeolite content and with an active a higher olefin yield with lower hydrogen transfer activity
matrix. Also, high reactor temperature reduces nitrogen (Figure 6.24).
adsorption whereas an increased C/O ratio counters the
nitrogen effect [41]. 6.8.3.2 Gasoline Sulfur Reduction Additive
A FCC unit generally contributes over 40 % to the refinery
6.8.3 FCC Additives gasoline pool. FCC gasoline contains sulfur compounds
FCC additives are specialty catalysts designed to achieve such as mercaptans, sulfides, disulfides, thiophenes,
certain objectives such as gasoline quality improvement, and benzothiophenes that account for most of the gaso-
enhancement of light olefin yields, higher conversions, line sulfur. These compounds are formed in the riser
reduced flue gas emissions, etc., without any modification either by cracking of heavier sulfur compounds or by

LPG
C3=
30
Yield, wt%

0
0 5 10 15 20 25 30
ZSM, wt%
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 6.24—Effect of ZSM-5 concentration on product yields [63].

AST-MNL58-11-0801-006.indd 149 3/12/13 2:02 PM

150 Petroleum Refining and Natural Gas Processing

Fuel gas 20-30% Table 6.6—Effect of GSR Additive on Yield

Pattern [71]
Products Delta Yields, wt % on Fresh Feed Basis
Gasoline 2-10%
GSR additive, 15 wt % A B

Dry gas +0.01 +0.17

Feed sulfur FCC LCO 10-35%
LPG -2.49 -1.87

Gasoline -0.84 -0.76

HCO 5-35% TCO +2.73 +3.46

CLO +0.57 -0.67

Coke, 3-30% Coke +0.02 -0.02

SOx
Sulfur reduction in 26 42
Figure 6.25—FCC feed sulfur distribution [64]. gasoline, wt %

6.8.3.3 SOx Reduction Additive

r ecombination of hydrogen sulfide (H2S) with olefins.
The source of SOx (a mixture of SO2 and SO3) emissions
Typically, 2–10% of FCC feed sulfur ends up in gasoline.
from FCC is the sulfur present on the coke that was depos-
Figure 6.25 shows the typical distribution of feed sulfur
ited on the catalyst during the reaction. SOx emissions are
in the FCC product.
hazardous because of the formation of acidic compounds
Thiophenic compounds are the major constituents of
in the environment. Typically, 10–30 wt % of sulfur in
gasoline. Benzothiophenes, which are present in the higher
feed contributes to SOx. SOx reduction additives are more
boiling range of gasoline, are difficult to crack. It is gener-
effective at adsorbing SO3 than SO2 under regenerator
ally believed that thiophene conversion requires hydroge-
conditions. SOx reduction additive contains mainly two
nation by hydrogen transfer (HT) from hydrogen-donor
components: one is an oxidizing agent that promotes SO2
molecules before cracking (Scheme 1).
oxidation to SO3 and the other one is a sulfur pick-up agent.
The main reactions of the process are represented in Figure
Scheme 1 6.26. Base catalyst or catalysts with high alumina can play
R R the role of sulfur pick-up agent for SO3 as shown in Eq 6.24.
R-C4 + H2S
S S HT cracking Al2O3 + 3 SO3 Al2 (SO4)3 (6.24)
(6.23)
The presence of excess oxygen or CO combustion promoter
To date, the gasoline sulfur reduction mechanism is not additive also oxidizes SO2 to SO3, thus reducing the load
fully understood. However, it is believed that the reduction on the SOx additive. Magnesium is the active metal in both
follows the cracking of sulfur species formed in the proof the additives. One is based on the spinel MgAl2O4 crystal
cess to release H2S or inhibition of the formation of sulfur structure with a cubic, close-packed array of oxides and
compounds. Harding et al. [65] have proposed that gasoline the other one is based on hydrotalcite {Mg6 Al2 (OH)18 45
sulfur reduction additives primarily enhance the rate of H2O}, which also has a layered structure with easy access
tetrahydrothiophene (THT) cracking to H2S, thus prevent- for SOx species. Efficiency of SOx removal varies from unit
ing its conversion to thiophene by hydrogenation reactions. to unit and the type of additive being used. While process-
Alternatively, gasoline sulfur reduction could be due to ing 1.1-wt % sulfur feed with a throughput of 3125 t/day,
improved HT to thiophenic species initiated by the increase approximately 11.5 Mt of SOx per a day is emitted. By the
of coke production [66,67]. Shan et al. [68] and Vargas-Tah addition of 10-wt % SOx reduction additive, a decline of
et al. [69] have proposed that sulfur reduction occurs by approximately 60 wt % SOx level is observed [72].
strong adsorption of thiophenic species on the Lewis acid
sites of the additive and further cracking. 6.8.3.4 CO Combustion Promoter
The dosage of additive varies from 10 to 40 wt % of the A CO combustion promoter catalyst is used to enhance CO
total FCC catalyst inventory on the basis of the feed and combustion in an FCC regenerator and to reduce the after-
product sulfur targets. Laboratory MAT or pilot plant tests burn. Variation of ΔT (the temperature difference between
have shown that these additives could decrease the sulfur the dense and dilute bed) and the concentration of CO are
content of FCC gasoline by as much as 40 % without sig- generally taken as measures for the performance of the
nificantly affecting other yields, excepting a slight increase additive in the FCC unit. Because of the higher heat of com-
of coke and hydrogen production. However, in some reports bustion, the dense bed temperature increases with CO pro-
[70] gasoline sulfur reduction additive addition caused moter addition. The active ingredient in the CO combustion
a substantial change in the yield pattern (Table 6.6). An promoter is a noble metal, mainly platinum. The addition
Indian refinery processing 1.3-wt % sulfur feed achieved rate of a CO promoter is typically in the range of 0.2–1 wt %
28–40 % gasoline sulfur reduction with addition of 15-wt % --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
of the base catalyst or 1 ppm of noble metal on the overall
GSR additive [71]. catalyst inventory [73]. The active metal is also occasionally
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Chapter 6 n Fluid Catalytic Cracking 151

Figure 6.26—Typical FCC unit SOx reduction chemistry [74]. Source: Figure used courtesy of Intercat, Inc.

incorporated along with the base catalyst. In the case of the Grace Davison studies, 50 % of the nitrogen in feed was
non-platinum-based additives such as palladium-based found in the bottoms and LCO, 5 % was released as ammo-
additives, higher addition rates are required because of nia in the riser reactor, and the rest was deposited as coke
lower activity. However, such additives also give the addi- on the catalyst. Nitrogen deposited on coke was mostly oxi-
tional advantage of NOx reduction. dized to molecular N2. NOx as the percentage of N2 in coke
varied from 10 to 25 wt % [62].
6.8.3.5 NOx Reduction Additive With the addition rate of 1–2 wt % additive, NOx can be
FCC alone contributes 50 % of the total NOx emitted in a reduced by almost 70 wt %. Although additive plays signifi-
refinery [75]. A partial-burn FCC regenerator without CO cant role in NOx reduction, FCC unit operating conditions
combustion promoter additive typically does not emit more greatly affect NOx. A high-oxygen environment typically
than 50–150 ppm NOx. However, units that are operated in favors NOx formation. The effect of oxygen concentration
full-burn mode may emit NOx as high as 500 ppm. As per on NOx content is presented in Figure 6.27. The addition
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 6.27—Variation of NOx with respect to regenerator oxygen [74]. Source: Figure used courtesy of Intercat, Inc.
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152 Petroleum Refining and Natural Gas Processing

of CO combustion promoters increases the NOx forma-

tion due to noble-metal-promoted oxidation. Likewise, the Table 6.7—Comparison of Physical
NOx additive performance is influenced by the presence of Characteristics of Catalysts
other gases such as SO2, SO3, CO, and CO2 [74]. NOx is also Physical Property Plant E-Cat Fresh Cat
reduced in the regenerator by reacting with coke.
BET surface area, m2/g 157 325
The typical reactions that help for NOx reduction are
as follows: Microporous area, m2/g 99 265

Matrix surface area, m2/g 58 60

2NO + CO N2 + CO2 + ½ O2 (6.25)
Micropore volume, cm3/g 0.04 0.1
2NO + C N2 + CO2 (6.26) Unit cell, Å 24.24 24.61

NOx reduction additives contain noble metals dispersed on

an inorganic support. The metals used are iridium and pal-
ladium. Irridium was found to be more selective because an average activity of particles of different ages, is lower
of its ability to dissociatively adsorb NO in the presence of than the fresh catalyst activity. Table 6.7 gives the typical
excess O2 [74,76,77]. properties of FCC fresh and e-cat samples. When selecting
a fresh catalyst, the equivalent e-cat activity of new cata-
lyst is needed, and this can be simulated in the laboratory
6.8.4 Selection of Catalyst by following a suitable laboratory deactivation method.
Selection and use of improved catalyst or additive substan- Laboratory deactivation procedures attempt to simulate
tially enhances the profit margins and is one of the quickest the changes that occur commercially under accelerated
ways for meeting refinery goals. Catalyst selection depends deactivation conditions [78].
on several factors such as product yields and quality
requirements, FCC unit constraints, the nature of the feed 6.8.4.2 Simulation of Catalyst Deactivation
being processed, the metal content of the feed, etc. Hence, Fresh catalyst is subjected to laboratory deactivation,
FCC catalyst selection is unit specific and may need to be which involves metal doping, reduction/oxidation, and
tailor-made to meet the refiner’s objectives. hydrothermal deactivation to simulate plant e-cat. Metals
A catalyst change should be considered whenever are loaded on the base catalyst over several cycles of crack-
there has been a significant change in feed quality, product ing using a metal-doped VGO feed followed by catalyst
demand, or unit hardware constraints. The availability of regeneration at conditions similar to those encountered
better catalysts over a period of time is also a key reason for in the commercial FCC unit [79]. Alternatively, metals can
the refiner to look for an alternative catalyst. To gainfully be doped directly by impregnation [80,81]. Metal species
exploit the new developments, a refiner should consider doped by an impregnation method are more active; hence,
catalyst change once every 2 years or sooner. only a fraction of the e-cat metals (~33 %) are targeted for
laboratory deactivation to match the properties of plant
6.8.4.1 Catalyst Selection Process e-cat.
Catalyst evaluation through laboratory microreactors or a
pilot plant provides valuable inputs for selecting an optimal 6.8.4.3 Commercial Yield Estimation
catalyst for the commercial plant. Major steps in the cata- Catalyst activity studies can be performed by bench-scale
lyst evaluation procedure are the laboratory deactivation units such as a MAT or a fluid bed simulation test (FST)
of catalyst to mimic the plant equilibrium catalyst (e-cat), Liquid and gaseous products are typically analyzed using
laboratory conversion studies on deactivated catalysts, standard analysis equipment such as a gas analyzer [gas
and modeling and simulation to translate the laboratory chromatograph (GC)] and a simulated distillation (SIM-
conversion results to the commercial-scale unit. For the DIS) GC, whereas coke is estimated through online or
convenience of the reader, a few frequently used terms are offline methods by burning the deposited coke. Microreac-
explained: tor yield data are the key input for mathematical models.
• “Fresh” fluid cracking catalyst is catalyst, as manufac- The mathematical models help in estimating the com-
tured and sold by catalyst vendors. mercial yields from the laboratory experimental data. The
• “Equilibrium” fluid cracking catalyst (e-cat) is the procedure involves estimating catalyst-dependent kinetic
inventory of circulating catalyst composition in an parameters from laboratory experiments and estimating
FCC unit once it has reached a steady state within the yields after incorporating suitable hydrodynamic aspects of
environment of the FCC unit. the FCC hardware. For this procedure to be accurate, one
• The coke-laid-down catalyst, which was taken out from must validate the model with several cases of plant data and
the FCC, is referred to as “spent catalyst.” carefully planned catalyst activity data.
Because of hydrothermal aging in a commercial
unit, a portion of zeolite and matrix loses its structural 6.8.5 Equilibrium Catalyst Monitoring and
integrity, leading to surface area and activity loss [34]. Troubleshooting
To maintain the desired activity, fresh catalyst (~1–2 % Monitoring of an e-cat provides valuable information per-
of the inventory) is added in a day, and an equal amount taining to operational, mechanical, and catalyst aspects,
of spent catalyst is withdrawn from the system. Thus, thus aiding in unit optimization and troubleshooting
the catalyst inventory in the unit is a mixture of differ- various unit problems. The data analysis sheet comprises
ent aged particles. Therefore, the e-cat activity, which is catalytic activity, physical properties, and chemical analysis
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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Chapter 6 n Fluid Catalytic Cracking 153

Table 6.8—E-Cat Data Analysis Sheet

Activity Physical Properties Chemical Properties

Surface Pore PSD (wt %)

Sample Micro Coke Gas Area Volume ABD Al2O3 C Na Fe Ni V Cu Sb
Date Activity Factor Factor (m2/g) (ml/g) (g/ml) 0–20 0–40 0–60 0–90 (Wt%) (wt %) (wt %) (wt %) (ppm) (ppm) (ppm) (ppm)

22.6.09 66 0.8 1 121 0.3 0.81 9 20 70 80 42 0.27 0.18 0.31 722 719 12 0

15.6.09 68 0.7. 1 125 0.28 0.83 10 19 69 82 42 0.23 0.17 0.29 519 733 7 0

18.5.09 71 0.9 1.2 122 0.26 0.81 7 22 73 84 42.7 0.22 0.19 0.29 464 854 7 0

11.5.09 70 0.8 1 118 0.34 0.78 8 22 68 80 43 0.35 0.18 0.32 625 740 14 0

27.4.09 71 0.7 1 119 0.33 0.80 11 18 65 88 43 0.27 0.17 0.31 600 720 22 0
Coke factor is relative number that is proportional to specific coke, defined as specific coke = coke yield × (100 – conversion)/conversion.
Gas factor is a relative number that is proportional to the specific hydrogen yield. Specific hydrogen is defined as specific H2 = H2 yield × (function of FST
conversion).

(Table 6.8) [41]. The e-cat monitoring is generally per- 6.8.5.2 Physical Properties
formed on weekly basis. The main physical properties are surface area, average bulk
density, particle size distribution, and the attrition index
6.8.5.1 Catalytic Activity measurement.
Catalytic activity includes the conversion of VGO to gas, liq- • Surface area (SA): Measurement of SA is an indirect
uid, and coke. These are measured in a MAT/FST unit using measurement of catalyst activity. A decrease in SA is an
standard gas oil feed at standard conditions. However, the indication of loss of activity. SA loss may be due to hydro-
MAT values can differ because each testing laboratory has thermal deactivation or metal deactivation of the catalyst.
benchmarked their own testing conditions against their • Particle size distribution (PSD): Monitoring PSD is
own feeds. helpful to identify the strength of catalyst and the unit
Activity is a measure of the catalyst’s ability to crack condition. A decrease in catalyst fines or loss of catalyst
heavy oils to lighter products. It is generally reported as indicates an imbalance in cyclone performance. An
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

second-order conversion, or Conv/(100 – Conv). The gas fac- increase in fines content shows increased catalyst or
tor indicates the effect of metals or change in fresh catalyst additives attrition. Figure 6.28 shows the changes in
formulation, which influences dehydrogenation activity of e-cat PSD with different problems in the unit.
the metals. The gas factor is a measure of a yield of gas • Attrition index (AI): AI measurement gives valuable
produced in the MAT/FST. The coke factor is a measure of information about the strength of the catalyst. The
the catalyst coking tendency. It is expressed as coke yield ASTM method for AI measurement is widely practiced.
divided by the second-order conversion. Higher metals However, different laboratories practice different test
increase the coke factor and are influenced by fresh catalyst protocol. An attrition measurement helps to predict the
properties. attrition behavior of fresh catalysts and additives. E-cat

Normal Fines Distribution in Cyclones Hole-in-One Cyclone Stage

10
Percent recovery,

8
recovery, wt%

10
6
Percent
wt%

4 5
2
0
0
0 20 40 60 80 100 0 20 40 60 80 100

Particle size, microns Particle size, microns

Cyclone Efficiency Comparison Presence of Attrition Source

Fines recovery, wt%

15 10
Percent recovery,

10 8
6
wt%

5 4
0 2
0 20 40 60 80 100 0
0 20 40 60 80 100
Particle size, microns Start of run
End of run Particle size, microns

Figure 6.28—E-cat particle size as an indicator of regenerator problems [83].

AST-MNL58-11-0801-006.indd 153 3/12/13 2:02 PM

154 Petroleum Refining and Natural Gas Processing

Attrition Index
GSR
additives
Octane /LPG Bottoms/
booster CO
FCC additives promoter
catalysts

FCC catalysts and additives

Figure 6.29—Attrition behavior of catalysts and additives.

attrition is performed only in the case of troubleshoot- Sodium is detrimental to the catalyst by deactivating
ing if there is excess generation of fines in the unit. the acid sites and causing the destruction of the zeolite
There is always wide variation of attrition properties crystal structure. Sodium inhibits HT reactions and
among the catalysts and additives. Figure 6.29 shows increases the olefins in gasoline. The tolerance limit of
typical values of different catalysts and additives [53]. commercial catalyst is approximately 4500 ppm with-
out affecting the conversion and catalyst structures.
6.8.5.3 Chemical Properties Approximately 6 points of MAT activity are lost per
Important chemical components include alumina, rare weight percentage of sodium originating from the FCC
earth, sodium, carbon on the regenerated catalyst, and met- feed. At high sodium levels the catalyst is also more
als (nickel, vanadium, sodium, copper, and iron). sensitive to high regenerator temperature because of
• Alumina (Al2O3): The regular measurement of alumina increased rates of sintering and SA destruction. High
content indicates the catalyst inventory, fresh catalyst fresh catalyst addition rates are required to recover
addition rate, or compositional changes in the catalyst from sodium poisoning [83].

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
or additives. • Nickel, vanadium, iron, and copper: Catalyst coke- and
• Rare earth content: Rare earth content is an indirect gas-making tendencies increase when these heavy
indication of the zeolite type that was used for fresh metals are deposited on the catalyst. Feed is the main
catalyst preparation. The rare earth element forms source of nickel and vanadium. The monitoring of
bridges among acid sites and protects the leaching of vanadium metal levels helps to predict the deactivation
acid sites from the framework. High rare earth content level of the catalyst. The loss in MAT activity with vana-
is an indication of high HT reactions, which are gaso- dium content on the catalyst is presented in Figure 6.28
line selective with low octane number. [84]. It was also found that approximately 1000 ppm
• Sodium (Na): E-cat sodium content is a combination of of vanadium on the e-cat reduces the sulfur species in
fresh catalyst sodium and the sodium present in feed. the gasoline range. Nickel promotes dehydrogenation

69
68
Micro activity, vol%

67
66
65
64
63
62
61
0 1000 2000 3000 4000 5000 6000 7000 8000

V, ppm
Figure 6.30—Variation in MAT activity with vanadium content [84].
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Chapter 6 n Fluid Catalytic Cracking 155

reactions, leading to gas and coke make. The contri- Riser temperature and the catalyst-to-oil ratio are the
bution to coke and gas make due to nickel, copper, key variables that decide the severity of FCC operation and
vanadium, and other metals is commonly reported hence are maximized for higher conversions. However,
through indices that are in nickel-equivalent form to maintain the heat balance between the riser and the
(e.g., Davison index: Ni + Cu + V/4). The metals are regenerator, only riser temperature can be varied indepen-
active when deposited first and their activity reduces dently whereas the catalyst circulation rate and regenerator
with continuous cycles of oxidation and reduction. On temperatures are bounded by the following heat balance
average, one-third of the nickel retains its dehydroge- relationships
nation activity [41]. It is observed that iron, present in • Riser heat balance: Enthalpy lost by the circulating cat-
organic and inorganic forms, affects the activity of the alyst = Heat of reaction + Enthalpy difference between
main FCC catalyst. Iron changes the surface structure, feed and product + heat losses
blocks pores, reduces ABD, and increases slurry yield. • Regenerator heat balance: Heat of coke combustion =
A common cause of iron contamination is malfunction- Enthalpy difference between flue gas and air + Enthalpy
ing of the crude desalting unit. Grace Davison reported gain by the circulating catalyst + heat losses
typical average e-cat iron levels to be 0.57 wt % [61]. A reduced feed temperature allows for higher catalyst
• Carbon: The carbon level on the e-cat is an indicator of circulation for a constant riser temperature. The increased
regenerator performance. FCC units operating in full catalyst circulation also decreases the regenerator bed
combustion mode have carbon levels of 0.05 wt % or temperatures because of higher heat removal as sensible
less on the e-cat, whereas partial combustion units have heat. The net heat of reaction, although endothermic, is a
a carbon level of 0.1 wt % or higher. Any variation indi- strong function of the type of feed and the catalyst used.
cates a problem due to coke burning in the regenerator. The HT reactions are exothermic; hence, the net heat of
The typical e-cat evaluation datasheet is shown in Table reaction with rare-earth-based catalysts is generally lower
6.8. FCC units generally experience catalyst-related prob- than the USY-based catalyst because of higher HT reac-
lems such as circulation, catalyst loss and activity decline, tions with the former. The recycling of unconverted feed is
and hardware-related problems. Regular monitoring of the typically practiced with low severity units and sometimes to
plant e-cat and fresh samples in terms of the physicochemi- balance the coke make or when catalyst fines loss is high.
cal properties and activity in the MAT unit helps refiners to Recycling of unconverted feed increases coke on catalyst
troubleshoot the unit problems in a more efficient manner as well as regenerator temperature. The catalyst activity
and maintain the desired activity. can be controlled through proper design and selection of
optimal fresh catalyst as well as optimal catalyst addition
6.9 Key Process Variables and Their rates [85]. Although there are several variables available in
Impact on Operations FCC, because of the heavy interdependence the refiner has
The FCC process includes many variables; hence, the design a narrow range of options for process optimization, which
or operating personnel must judiciously use them for meet- needs to be exploited gainfully.
ing the process objectives. The important independent
variables available for the refiner are riser temperature, 6.10 Diverse Applications and
feed flow rate, feed inlet temperature, catalyst activity and Continuous Improvements
composition, and recycle rates, whereas the key dependent The FCC process, which was originally invented for gaso-
variables include catalyst circulation rates, regenerator line production, has evolved over the last 60 years. Figure
temperature, and conversion [34]. 6.31 summarizes the key technological milestones and the

Theoretical Octane Barrel

6200

New reactor concepts

6000
Improved reaction
Octane Barrels/100 Barrels Feed

5800 systems

Octane catalysts
5600

Extended riser
5400
Zeolite catalysts
5200
Amorphous
catalyst
5000

4800
1940 1950 1960 1970 1980 1990 2000

Figure 6.31—Summary of the key technological milestones and the progress with reference to theoretical targets over these years.
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156 Petroleum Refining and Natural Gas Processing

progress with reference to theoretical targets [86]. Over and reliability are other drivers that are likely to further
these years, the process has been successfully adapted to catalyze the new innovations.
maximize diesel and LPG through changes in catalyst and
operating conditions. The LPG mode of operation has been Acknowledgments
further improved to selectively maximize either propyl- The authors gratefully acknowledge generous inputs from
ene or butylene. Propylene production is attracting major M/s KBR, Inc., Axens/Shaw, Exxon Mobil, UOP, Albemarle,
attention because of huge demand, and it is estimated that Grace Davison, Intercat, PSRI, and BPCL management for
nearly 30–40 % propylene would be produced through FCC. giving permission to publish this work.
Propylene-selective DCC technologies are commercially
available from licensors such as UOP, Stone and Webster/ References
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7
Hydroisomerization of Paraffins in Light
Naphthas and Lube Oils for Quality
Improvement
B.L. Newalkar1, N.V. Choudary1, and M.A. Siddiqui1

7.1 Introduction hydroisomerization and hydrofinishing step, respectively.

With an increased worldwide environmental concern, the This can be seen from Table 7.2, in which the effect of

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operation of the modern refinery is becoming more and more hydrocarbon types on the properties of lube oil is sum-
complex for meeting stringent transportation fuel specifica- marized. The aforementioned features give performance
tions. For gasoline the challenge is to maintain high octane characteristics in finished lubricants very similar to synthetic
while meeting stricter requirements for Reid vapor pressure ones such as poly-alpha-olefins (PAO).
(RVP), removing lead-based antiknock agents such as tet- On the basis of these features, the American Petroleum
raethyl lead, removing of benzene, aromatic control, lower Institute (API) established a base oil classification as given
sulfur content, and the impending ban of the gasoline oxy- in Table 7.3.
genate methyl tertiary butyl ether (MTBE) and other homo- Most of the above developments were possible because
logues with longer alkyl side chains. However, the reduction of significant advances over the last 3 decades in the selective
in high-octane possessing aromatics, olefins, and oxygenate hydroconversion of n-alkanes into their branched isomers.
components would result in the lowering of octane number Thus, this chapter is aimed at understanding the chemistry of
of gasoline. Thus, to compensate for the RON loss, the highly catalyst developments in the evolution of hydroisomerization
branched alkanes are a desired alternative because of their processes along with their salient features.
high octane numbers (Table 7.1) to produce reformulated
gasoline (RFG) [1,2]. 7.2 Process Thermodynamics and
Because of this, hydroisomerization of light naphtha, Catalyst Chemistry
which produces isoparaffin-based high-octane gasoline blend The hydroisomerization of n-paraffin is a thermodynamic
stock from light- and mid-cut naphtha, has gained impor- equilibrium-driven reaction with mild exothermicity on the
tance in recent time. Hydroisomerization (light naphtha for order of –4 to –20 kJ/mol. It occurs without any variation
gasoline) accounts for approximately 2 % of the total crude in the number of moles and is therefore not influenced by
processed, and naphtha hydroisomerization capacity has variations in pressure [4].
increased from 1.26 million barrels per day (mbpd) in 1995 The hydroisomerization reaction is always accom-
to 1.51 mbpd in 2002. It is further estimated to increase at panied by a hydrocracking reaction that lowers more or
the rate of 5.8 % per year [2]. less the yield for the isomerized hydrocarbons. The rates
Similarly, futuristic demands for base oil in terms of for the isomerization and cracking steps determine the
higher purity, high viscosity index (VI), lower volatility, and product distribution. It may be noted that the rates of
longer life has led to emergence of a hydroisomerization- the hydroisomerization and hydrocracking of alkanes, as
based dewaxing route in the early 1990s for the production of two competitive reactions, strongly depend on the carbon
lube oil base stock (LOBS) [3]. Lube base oils produced by numbers in the feed molecules [5,6]. Light alkanes such as
hydroisomerization-based dewaxing, coupled with hydro- n-hexane can be cracked only slowly via the secondary car-
finishing in conjunction with severe hydrocracking, offer benium ions as transition states, leading to a high selectivity
the following attractive features: to isomerization. On the other hand, multibranched isomers
• Very high VI (100 to 130), of long-chain n-paraffins are more prone to cracking
• Low volatility, because of their adsorption ability over the catalyst surface
• Superior oxidation resistance, than those of the short-chain, multibranched isomers of C5
• High thermal stability, and C6 paraffins that constitute light naphtha [5,6]. Thus, to
• Excellent low-temperature fluidity, and decrease cracking reactions, one must limit multibranching
• Low toxicity. at its optimal level to have a successful hydroisomerization
These features in the lube oil are achieved by increasing of long-chain n-paraffins [5,6]. On the basis of the afore-
the isoparaffins and maximizing saturates by means of the mentioned considerations, the best adapted catalysts to this

1
Bharat Petroleum Corporation, Ltd., Greater Noida, India

159
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160 Petroleum Refining and Natural Gas Processing

The pictorial representation of the aforementioned

Table 7.1—RON of Pure Paraffins steps is illustrated as follows:
Paraffin RON Paraffin RON
-2H
n-Butane 113 2,3-Dimethylbutane 96 n-alkylcarbonium ion
D
+
±H C
Isobutane 122 n-Heptane 0 ± 2H ±H
+
n-alkane n-alkene n-alkykcarbenium ion
A B
n-Pentane 62 2-Methylhexane 41
E F
2-Methylbutane 99 3-Methylhexane 56 G
monobranched monobranched cracked
alkane alkylcarbenium ion product
2,2-Dimethylpropane 100 3-Ethylpentane 64

n-Hexane 19 2,2-Dimethylpentane 89
dibranched dibranched cracked
2-Methylpentane 83 2,3-Dimethylpentane 87 alkane alkylcarbenium ion product

3-Methylpentane 86 2,2,3-Trimethylbutane 113

tribranched tribranched cracked
2,2-Dimethylbutane 89 alkane alkylcarbenium ion product

where:
A = hydrogenation-dehydrogenation on metal sites,
Table 7.2—Lube Oil Components and Their
B = protonation-deprotonation on acid sites,
Properties
C = addition of proton to form alkyl carbenium ion on
Value acid sites,
Hydrocarbon Pour in Lube D = dehydrogenation to form alkyl carbenium ion,
Type Viscosity VI Point Stability Oil E = competitive adsorption-desorption of alkene and
n-Paraffins High High High Medium Very carbenium ion on acid sites,
(wax) low F = rearrangement of alkyl carbenium ion, and
G = cracking of alkyl carbenium ion.
i-Paraffins Medium High Medium Medium High
In view of the above, the preferred consecutive steps for
Naphthenes High Low Low Medium Medium successful isomerization are summarized as follows:
• Dehydrogenation on the metal,
Aromatics Low Low Low Low Very
low
• Protonation of olefins on the Brönsted acid sites with
formation of a secondary alkyl carbenium,
• Rearrangement of the alkyl carbenium ion via formation
of cyclic alkyl carbenium-type transition state,
Table 7.3—API Classification of Base Oils • Deprotonation, and
Group Saturate wt % Sulfur wt % VI • Hydrogenation on the metal.
Thus, it is imperative that the ideal hydroisomerization
I <90 >0.03 >80 to <120
catalyst must have an optimal balance between metal and
II ≥90 ≤0.03 ≥80 to ≤120 acid functions to favor isomerization. The degree of isom-
III ≥90 ≤0.03 ≥120
erization in terms of branching usually depends on the
targeted application. For example, multibranched paraffin
IV All PAOs isomers are desired to achieve the RON (Table 7.1) whereas
V All base stocks not included in groups I–IV mono- and dibranched paraffins are more preferred as lube
oil components (Table 7.2) to meet the VI parameter for lube
oil. Therefore, it is but obvious that catalyst requirements
reaction must be tailored to favor hydroisomerization over differ for light naphtha and lube-range paraffin isomerization,
hydrocracking reactions. respectively. Thus, catalysts for light naphtha isomerization
Hydroisomerization catalysts are bifunctional in nature are designed to produce multibranched paraffin isomers
and consist of a metal, such as platinum (Pt), dispersed on whereas those of wax isomerization are tailored to favor
an acidic support. The metal function acts as a dehydro- mono- and dibranched long-chain paraffin isomers. Typical
genation/hydrogenation agent whereas the acidic support features of such catalysts are described in the following
is responsible for the skeletal isomerization reaction of section.
the olefinic intermediates formed over the metal sites and
cracking. If the metal and acid functions on the catalyst are 7.3 Hydroisomerization Catalysts
well balanced, the catalysts are referred to as ideal bifunc- 7.3.1 Catalyst for Light Naphtha Isomerization
tional catalysts. Over these ideal bifunctional catalysts, the Light naphtha isomerization suffers from thermodynamic
hydrogenation and dehydrogenation reactions occur rapidly limitations (Figure 7.1) and equilibrium shifts toward low-
and the rearrangements of the hydrocarbon intermediates octane isomers at higher reaction temperature (e.g., from
over the acid sites constitute the rate-determining steps. As dimethylbutanes via methylpentanes to n-hexane) [6]. On the
a consequence, the hydroisomerization and hydrocracking other hand, the rate of reaction can become a limiting factor
reactions appear to occur consecutively, with the sequence at lower temperatures for achieving the desired RON. There-
of products being monobranched isomers, dibranched
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fore, it is desirable to use very active catalyst to perform this
isomers, and then cracked products [5,6]. reaction at a lower temperature. The catalysts used for the
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Chapter 7 n Hydroisomerization of Paraffins in Light Naphthas and Lube Oils 161

100 advantage of the thermodynamic equilibrium as illustrated

90 (a) Isopentane in Figure 7.1 [5,6].
80 n-Pentane
However, such catalysts demand feed pretreatment
Neopentane
because they are sensitive to poisons such as feed sulfur
70
and in particular water [4]. The feed sulfur acts as a poison
60 for metal function whereas water reacts with the catalyst
mole %

50 chloride leading to formation of HCl. Thus, the continuous

40 injection of chlorine compounds during operation are often
30 found to pose handling and corrosion problems with such
catalysts. Therefore, the necessity to develop an alternative
20
catalyst in terms of acidic supports was clearly evident. This
10 has led to the development of molecular sieve zeolite-based
0 catalyst supports.
273 373 473 573 673 773 873 973 In view of the above, numerous studies have been
Temperature (K) performed over the last 3 decades using various zeolite
structures, metal oxide frameworks, and sulfated zirconia to
develop new catalyst recipes for light naphtha isomerization.
100 In this context, excellent reviews and monographs have
(b) been published [7–10].
90 2-Methylpentane
Solid acids such as zeolites are active for alkane isom-
80 n-Hexane
erization although the higher temperature is required
3-Methylpentane
70 compared with Pt/Al2O3-based catalyst. In the case of Pt-
2,2-Dimethylbutane
60 supported zeolite catalysts, the chlorination (and feed of
mole %

2,3-Dimethylbutane
50 chlorine-containing compounds) is not required because of
40
the higher acidity of zeolites. However, they are found to
be highly tolerant for feed contaminant, especially water.
30
In fact, Pt-supported mordenite zeolite was commercially
20 used in early 1970s by Shell in a process called Hysomer
10 for C5-C6 isomerization.
0
273 373 473 573 673 773 873 973 7.3.1.1 Zeolite-Based Catalyst (e.g., Y, Beta,
Temperature (K) Mordenite, ZSM-5)
Crystalline aluminosilicates, commonly known as zeolites,
Figure 7.1—Thermodynamic distribution of (a) C5 and (b) C6 are microporous in nature. They are generally classified into
paraffins.
three categories: small-, medium-, and large-pore crystalline
materials [11,12]. The acidity of the zeolite framework is
earlier industrial isomerization of light n-paraffins (n-C4-n-C8) dependent on the framework silicon (Si)/aluminum (Al)
were Friedel–Crafts catalysts such as AlCl3 with additives ratio. The framework acidity is found to increase with an
such as SbCl3 and HCl. These catalysts were strongly acidic increase in the framework Al content. The unique pore size of
and very active even at 353–390 K [4]. However, the processes approximately 5–7 Å for medium-pore zeolites offers shape
using these catalysts do not exist anymore because of the selectivity in terms of reactant, product, and transition-state
problems of corrosion of the reactor and the disposal of selectivity, as displayed in Figure 7.2 [11–13].
the spent catalysts. Moreover, they were very sensitive to The fine tuning of the characteristic framework proper-
poisons such as water, aromatics, and sulfur [4]. These ties of zeolite offer a platform to develop a catalyst having
disadvantages have added impetus to the development of
new/improved catalysts in this field.
The second-generation catalysts introduced were simi-
lar to reforming catalyst having a bifunctional role. Typically,
Pt/alumina was used. However, these catalysts were found
to be effective in the high temperature range wherein signifi-
cant cracked products were formed. Thus, such catalysts are
prone to rapid deactivation and thermodynamic limitations
on conversion per pass [4].
To overcome these problems, bifunctional catalysts
having increased acidity, via halogenation, to operate at
lower temperature are introduced. Thus, Pt-loaded chlo-
rided alumina is used. In the case of Pt/Al2O3 catalysts,
Al2O3 is chlorinated to improve acidic character by a
chlorine-containing organic compound, which is continu-
ously supplied during operation to compensate for the loss Figure 7.2—Shape selectivity concepts valid for n-C 7
of chlorine on the surface. This catalyst is very active and hydroconversion: (top) reactant selectivity (RS), (middle)
can operate at lower temperatures (370–470 K), thereby product shape selectivity (PS), and (bottom) transition state
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

yielding a greater proportion of branched alkanes by taking selectivity (TS).

AST-MNL58-11-0801-007.indd 161 3/12/13 2:07 PM

162 Petroleum Refining and Natural Gas Processing

controlled acidity levels by tuning the Si/Al ratio and ion enhancement of n-C7 isomerization compared with cracking.
exchange of the extra framework of cations, thereby leading Such a system is usually termed a trifunctional catalyst in
to low coke tendency; high hydrophobicity with an increase which to the usual bifunctional catalytic site configuration
in the Si/Al ratio; high aromatic, organic nitrogen, and sulfur a new cationic site is added for which the main role is to
resistance; and easy regeneration ability for light alkane speed up the desorption of olefinic species from the acid
isomerization. Zeolites such as Y, ZSM-5, mordenite, and site and its transfer to the metallic Pt site [29]. In such a way,
beta-based catalyst have particularly been exploited. Typical the residence time of the branched carbocation on the zeolite
pore dimensions of these zeolites are listed in Table 7.4. acid site is much shorter than the conventional bifunctional
Since the introduction of the Hysomer process, catalyst, thus avoiding further undesired cracking. For this
mordenite-type zeolite has been extensively investigated for purpose, zinc species are found to be ideal and are reported
light alkane isomerization. Thus, the activity and selectivity to behave as a Lewis acid site during reaction [28].
of hydroisomerization of n-C5-C6 alkanes over Pt/mordenite Pt/HBEA catalysts also show higher activity and selectiv-
is reported to be influenced by acid leaching [13]. Activity ity (exceeding 86 %) in the hydroisomerization of n-heptane
and selectivity are found to favor primary products, namely [28,29]. It has recently been demonstrated that a large-pore
branched isomers. Such improvements are ascribed to the tridimensional zeolite Beta, especially when synthesized with
modification of pore structure because of mesopore forma- smaller crystallite sizes, can be better than mordenite to
tion during the acid leaching process [13]. These mesopores isomerize n-C7 paraffin, which is one of the major constitu-
in turn are responsible for providing accessibility for more ents of the gasoline pool [5,6].
reactive sites and help in faster diffusion of formed products, Selective isomerization of n-heptane has also been
thereby reducing the chances of coke formation and the investigated over one-dimensional zeolites. On the basis of the
subsequent deactivation of catalyst. reported studies, ITQ-4, a unidirectional zeolite, is found to
In view of the thermodynamic limitation for n-C5 be more selective for the isomerization of n-heptane than
and n-C6 isomerization, particularly at high temperature, mordenite [30]. Selectivity and kinetic parameters observed
increasing efforts are made to develop a zeolite-based cata- in the hydroconversion of n-C5-n-C7 on 12MR unidirectional
lyst for n-C7 and n-C8 isomerization. This is primarily because zeolite (ITQ-4) indicate that differences in pore topology are
(1) 2-methylhexane, 2,3-dimethylpentane, and isooctane have more important than acidity for determining isomerization
research octane ratings of 53, 93 and 100, respectively; and selectivity [30]. Likewise, one-dimensional zeolite ZSM-
(2) no effective catalyst for C7 or C8 paraffins is currently 12-based catalyst is found to be active for isomerization of
in use because of the high tendency of their multibranched n-heptane [31].
isomers to crack. A brief overview of such investigations is The hydroconversion of C8-alkanes has also been
given below. studied extensively [31–41]. The hydrocracking and
On the basis of the open literature, zeolites with differ- hydroisomerization of n-octane, 2,5-dimethylhexane,
ent pore sizes and topologies and different crystallite sizes and 2,2,4-trimethylpentane on Ni/ZSM-5, mordenite, and
such as mordenite, ZSM-5, ZSM-12, ZSM-22, beta zeolites, Beta-zeolite was investigated at 533 K and 20 atm total
and Y zeolites have been investigated for this purpose [14–29]. pressure [36]. On the basis of the obtained results, the activity
Pt/mordenite is found to be less selective when dealing with decreased in the sequence ZSM-5 >> Beta ~ Mordenite for
longer paraffins such as n-C7 and n-C8 because of their high the n-octane conversion and increased in this sequence
acid strength. However, the selectivity of reaction on Pt/ for the conversion of 2,5-dimethylhexane and 2,2,4-
mordenite catalysts could be significantly improved by trimethylpentane. The selectivity for n-octane and
increasing the reaction pressure and by increasing the Si/Al 2,5-dimethylhexane isomerization was the highest on Ni/
ratio [28]. On the other hand, Pt/UY catalysts are reported Beta and lowest on Ni/HZSM-5.
to be active and selective in n-C7 isomerization with up to The activity, product selectivity, and stability of several
94 % selectivity at 72 % conversion [46]. On similar lines, Pt- and Pd-loaded zeolite catalysts (ZSM-5, ZSM-12, mor-
ZSM-5 and zeolite Y-based catalysts have been evaluated denite, USY, and Beta) with different Si/Al ratios have been
[10]. However, such catalysts are found to favor hydro- compared for the hydroisomerization of n-octane [38,39].
cracking over hydroisomerization because of their strong Accordingly, the catalytic activity is reported to decrease
acidity. Attempts have been made to modify the acidity in the following order: ZSM-12 > Beta > MOR > USY and
and acid site density for these zeolites for optimizing their ZSM-5 >> Beta > MOR [38]. The branched product selec-
performance for hydroisomerization of n-C7-C8 paraffins tivity is found to increase with the increase in Brønsted
[10]. Furthermore, ion exchange of metals such as zinc, acid strength. Among the investigated zeolites, ZSM-12, which
nickel, and cadmium in zeolite Y has resulted in significant has a one-dimensional channel (5.6 × 6.0A°), demon-
strated superior stability even under accelerated coking
conditions [37]. On the other hand, USY and Beta-zeolites,
Table 7.4—Zeolite Pore Dimension Data because of their relatively large pore sizes, allow to a higher
extent the branching of n-octane at the same level of conver-
Zeolite Zeolite Type Index Pore opening (Å)
sion in comparison with ZSM-12. According to the results
Beta BEA 5.7 × 7.5, 5.6 × 6.5 of these works, the zeolite acidity (number and strength
distribution) and the pore structure are inferred to play very
Mordenite MOR 6.5 × 7
important roles in the conversion and product selectivity
Y FAU 7.4 × 7.4 for the hydroconversion of n-octane.
USY FAU 7.4 × 7.4 Attempts have also been made to explore the zeolite
membrane reactor concept for the hydroisomerization
USY = Ultrastable Y
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- of n-hexane and n-heptane, respectively, using silicalite-1
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Chapter 7 n Hydroisomerization of Paraffins in Light Naphthas and Lube Oils 163

membrane [42,41]. The results obtained indicate separation because of which they are prone to feed contaminants such
selectivities with factors close to 20 for n-, mono-, and as water and sulfur [5,6,10].
dibranched components in a gas mixture as well as n-hexane Attempts have been made to use strong solid acid-based
conversions up to equilibrium values over zeolite mem- anion-modified zirconium oxide as a support to prepare cat-
brane. The research octane number (RON) calculated for alysts for the hydroisomerization of n-paraffins. It is found
the product stream of the different experiments indicates that SO42–/ZrO2, commonly known as SZ when used as a
numbers as high as 85. For the hydroisomerization of C7 support for Pt loading, exhibits high activity and selectivity
alkanes, a concept of two reactors and a zeolite membrane in C4-C6 n-paraffin isomerization [10]. In this context, the
has been proposed and an industrial-scale process is simu- role of zirconia crystal structure in determining isomeriza-
lated. Although the calculated product yield is found to be tion selectivity is investigated. Accordingly, the monoclinic
approximately 24 % of the process feed, an improvement in zirconia phase is found to favor the isomerization of light
a RON from 57 for the feed to 92 for the product has been n-paraffins [46]. Later, the joint research of Cosmo Oil Ltd.
noticed. Both processes show that the application of zeolite and Mitsubishi Heavy Industries led to the development
membranes in the hydroisomerization of light alkanes can of the process for the isomerization of light naphtha using
result in an octane number higher than in the “state-of-the- such catalyst. The process was commercialized by UOP
art” processes [43]. LLC [47]. On similar lines, M/s Sud-Chemie has developed
Attempts are also been made to exploit the composite a catalyst system that is based on a modified SZ (super
zeolite system to improve the isomerization selectivity. Such acid), called HYSOPAR catalyst, which has been claimed to
a system consists of a combination of catalyst component, be tolerant up to approximately 100 ppm feed sulfur [48].
which converts the n-alkanes into monobranched isomers, This catalyst is successfully used in the Par-Isom process as
and a large-pore catalyst system. This in turn is reported to described in Section 7.4.
enhance the yield of multibranched isomers. [5,6] Thus, a
varied combination of acid form of zeolite Y and H-ZSM-5 7.3.1.3 Heteropoly Acids and Their Metal
has been investigated on hydroconversion of light alkanes Salts
(n-C6-C8) in the literature. The overall conversions observed Heteropoly acids, such as H3PW12O40 (WPA), are known to be
for the aforementioned zeolite mixtures are found to be in highly acidic and catalyze many kinds of reactions as a solid-
line with those predicted by the additive criteria, but the acid [49–54]. Palladium salts of WPA supported on silica
selectivities are found to be clearly different for the reaction are highly active for the isomerization of n-hexane under
products. Likewise, Pt/Beta-zeolite catalyst also improved hydrogen. WPA supported on commercial Pd/C is even more
the catalytic activity in the hydroconversion of n-octane active. This catalyst shows 96.4 % selectivity for n-hexane
when it is mixed with bentonite because of the synergetic isomers at the conversion of 77.9 % at 523 K. On the basis of
effect between extra-framework Al species and the acid such selectivity, the unique role of Pd and heteropoly anions
sites [5,6]. Similarly, a catalyst composed of the sulfated has been proposed [52–54]. The metal dissociates H2 to form
zirconia (SZ) and zeolite has showed enhanced activity in H atoms, which in turn react with heteropoly anion to form
the hydroconversion of n-octane [5,6]. proton and the reduced form of the anion as shown below:
Extending the mixed catalyst system, attempts have
been made to explore the catalytic potential of a system Pd
consisting of bimodal pore size distribution. Thus, the com- H2 ↔ 2H
posite catalysts containing the acidic zeolitic component H + PW12O403– ↔ H+ + PW12O404–
(Pt-MCM-22, Pt-Beta) and an inert mesoporous material
(MCM-41) have been prepared. These composites showed The catalytic activity is reported to change reversibly with
higher activity and higher selectivity in the hydroisomeriza- hydrogen pressure, indicating that reactions are reversible.
tion of n-heptane because of improved diffusion properties of Likewise, Cs2.5H0.5PW12O40 was active for n-alkane isomeriza-
the catalytic system. This trend has led to the discovery of a tion and the activity was more stable under hydrogen when
new composite family of materials known as “TUD-1” with the material was loaded with Pt [54].
significantly broader catalytic utility as well as enhanced
structural, thermal, and hydrothermal stability compared 7.3.1.4 Molybdenum/Tungsten Oxycarbide
with MCM-41 [44,45]. It has been shown that zeolite/TUD-1 and Partially Reduced MoO3
composites can have a significant synergistic catalytic The possible replacement of noble metal-based catalysts
effect [5,6]. for the isomerization of alkanes has been one of the prime
focuses to develop cost-effective hydroisomerization catalyst.
7.3.1.2 Amorphous Oxides or Mixture of In contrast to noble metal-supported catalysts, the use of
Oxides (SiO2–Al2O3, SO42–/ZrO2) transition metals is found to be ineffective in the hydro-
The first alternative commercial catalysts used for hydroconversion of alkanes because of their strong affinity for
conversion of light n-paraffins were based on amorphous intermediate reaction species. However, lattice substitution
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

inorganic oxides, such as mixed silica-alumina (MSA). with nonmetals such as S, C, O, and N atoms in transition
Successful attempts have been made to synthesize MSA sup- metals such as Mo and W deeply modifies the electronic
ports with mild Brönsted acidity, a very high surface area, structure of the parent metals, thereby boosting its activity
and a narrow pore size distribution in the mesopore region. comparable to that of noble metals. Therefore, in recent
The supports so obtained are reported to demonstrate the times, the use of transition metal carbides of tungsten carbide
best selectivity for light n-paraffins. However, similar to tra- (WC) and Mo2O as catalysts has received significant attention
ditional alumina-based catalyst, MSA-based catalyst demands because of their comparable catalytic properties with noble
constant chlorination to maintain acidity and acid density, metals [55–58]. Thus, WC treated with oxygen at 800 K is
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164 Petroleum Refining and Natural Gas Processing

active for isomerization of n-hexanes and n-heptanes. The • Saturate benzene present in the feed (it may be noted
dehydrogenation–hydrogenation function is offered by the that benzene saturation is a highly exothermic process);
patches of carbide, whereas the acidic function is offered by • Handle naphthenes (it may be noted that naphthene
patches of tungsten oxide. The product distribution using this limit isomerate yields as they preferentially adsorb
catalyst system showed the formation of 3,3-dimethylpentane over catalyst surface) and produce less coke than naph-
during the isomerization on n-heptane [56–57]. The large thenes under hydrodecyclization, thereby allowing for-
improvement in isomerization selectivity is observed when mation of coke precursors at higher temperature; and
the surface of molybdenum carbide (Mo2C) is oxidized [55]. • Isomerize cyclohexane (RON 83) to methylcyclopentane
The molybdenum oxycarbide (MoOxCy) thus prepared is (RON 91) to gain advantage of RON despite the presence
reported to be highly selective even for the isomerization of of feed naphthenes.
n-heptane and n-octane [58]. In this context, Pt/alumina has been extensively practiced
Partially reduced MoO3 at 623 K is reported to give a because of its mild operation severity (373–423 K), its high
high surface area and demonstrates a high catalytic activity selectivity for C5 and C6 isomers, and its ability to saturate
and selectivity for n-heptane isomerization. However, the benzene. Thus, it has undergone significant improvements
activity is found to be very much dependent on the degree at the commercial level. Today, the bulk density of alumina
of reduction (on time and temperature of exposure to support used in the catalyst preparation can be tailored, and
hydrogen). Interestingly, the catalyst is most active when the low-bulk density alumina offers not only high volume activity
Mo oxidation number is between 2.5 and 3.5. On the other but also lower fill costs and Pt requirements associated with
hand, MoO3 loaded with transition metals is more active than low density. The reduction in Pt content is possible because
MoO3 without metal loading for n-heptane isomerization the Pt function in the catalytic reaction does not limit the
under hydrogen after it was reduced with hydrogen [57,58]. rate of isomerization. Furthermore, advances in the chlo-
Among transition metals, Pt is found to be the most effective rination step offer higher site density over the alumina
metal. The role of Pt is suggested to enhance the formation surface, which allows low-temperature operation of the Pt/
of the HxMoO3 phase, which is the precursor to the active alumina system to favor the formation of more branched
MoOxHy phase. compounds for achieving RONs higher than 87.5. However,
The catalytic activity and selectivity for n-octane, performance of the Pt/alumina system is prone to feed
n-heptane isomerization over MoOxCy at 563 K demonstrated containing high naphthene content as well as water. Gener-
high selectivity of 95 % even at high conversion of 75 % for ally, naphthenes are adsorbed strongly, thereby inhibiting
C8 isomers and approximately 90 % even at 78 % conversion adsorption of n-paraffins over the alumina surface, whereas
for C7 isomers, respectively [57]. However, the mechanism water leaches out surface chloride. Thus, the feed naphthene
of isomerization is yet to be established, but it is worthy content needs to be controlled to the optimal level for
to note that these groups of catalysts are very selective for achieving the desired RON over the Pt/Alumina system. In
n-heptane isomerization. view of the commercial requirements, catalyst manufactur-
ers M/s Axen (ATS-2L) and M/s AkzoNoble-Total (AT-2G)
7.3.1.5 Commercial Catalysts for Light have introduced advanced Pt/alumina-based catalyst with
Naphtha Isomerization increased water tolerance to meet the aforementioned
Although, numerous attempts have been made for catalyst requirements of refiners.
development for light naphtha including C7 and C8 isom- On the other hand, commercial catalyst systems based
erization, commercial exploitation of the aforementioned on Pt/mordenite are less prone to feed naphthene content
catalysts is limited. The commercial utilization is typically but demand energy-intensive conditions vis-à-vis Pt/alumina
governed by catalyst because of their lower activity at lower tempera-
• Selectivity for isomerization, ture. The higher operating conditions (Table 7.5) for such
• Cost of catalyst (support), catalyst often limit the RON boost per pass because of the
• Isomer yields, thermodynamic limitations of the process. However, such
• Operation parameters, a catalyst system does offer the benefit of capital saving in
• Efficiency for benzene saturation, terms of feed pretreatment because of its high tolerance
• Lower fill cost, for water. Unlike alumina, flexibility in tailoring the bulk
• Minimum noble metal content, density is limited with zeolite-based catalyst, which limits
• Tolerance for naphthene content, and the possibilities of lowering the Pt content, thereby making
• Catalyst and cycle life.
Before naphtha isomerization, feed is hydrotreated to
remove feed contaminants such as sulfur. The obtained Table 7.5—Comparison of Operating
hydrotreated naphtha undergoes distillation to obtain light Conditions for Pt/Al2O3 and Pt/Zeolite
naphtha (IBP-303 K–FBP 363 K) and heavy naphtha (IBP- Systems
363 K-FBP 473 K), respectively. The light naphtha cut is Operating Conditions Pt/Al2O3 Pt/Zeolite
routed to the isomerization unit whereas heavy naphtha
is routed through the reformer unit. Today, with stringent Temperature (K) 373–463 523–543
gasoline specifications, especially with reference to benzene Pressure (Psi) 20–30 15–30
limits, refiners are restrained to process benzene precursors
Space velocity (h ) –1
1–2 1–2
through the reformer unit; hence, isomerate feed typically
contains benzene and its precursors (cyclohexane and H2/HC (mol/mol) 0.1–2 2–4
methyl cyclohexane). Therefore, it is of utmost importance
RON per pass 83–84 78–80
to use a catalyst that can --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Copyright ASTM International

AST-MNL58-11-0801-007.indd 164 3/12/13 2:07 PM

Chapter 7 n Hydroisomerization of Paraffins in Light Naphthas and Lube Oils 165

it costly compared with alumina catalyst. Typical operating • Optimal acid site distribution on the surface,
conditions used for both of the catalyst systems are listed • Increased external surface area, and
in Table 7.5. • Submicron zeolite crystallite size.
In view of the aforementioned advances in alumina In view of this, Al framework distribution as a function
science, Pt/alumina catalyst has gained commercial edge and of the Si/Al ratio can be judged as an important parameter
sometimes even outweighs the zeolite-based catalyst from to control optimal acid strength at the pore mouth. Like-
techno-commercial aspects. wise, particle size in the submicron region is envisaged
to offer an increased platform to favor a pore mouth/key-
7.3.2 Catalysts Long-Chain Paraffin lock-type mechanism. These aspects for potential zeolites,

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Isomerization namely ZSM-22, ZSM-23, ZSM-48, and SSZ-32, have been
The demand for improved lube oil with respect to VI, addressed in the patent literature.
pour point, oxidation stability, and need for gross refinery On the basis of the open literature, medium-pore
margin (GRM) improvement has added impetus for the zeolites viz. ZSM-22 (TON) and ZSM-23 (MTT) are found
development of a new catalyst chemistry since the late 1980s. to be highly selective for hydroisomerization of long-chain
Accordingly, lube oil dewaxing processes have also under- paraffins [60–64]. With ZSM-22/ZSM-23 zeolite catalysts, the
gone step change from a solvent dewaxing to catalytic- branchings are generated at very specific carbon positions
cracking-based dewaxing to hydroisomerization-assisted along the alkane chains as revealed in the conversions model
dewaxing processes with increased yields vis-à-vis solvent for n-alkanes with carbon numbers up to n-C24 [62]. On
and catalytic cracking dewaxing processes. The catalyst used the basis of the developed model, monobranched isomers
for this process differs significantly from those practiced with branching at the C2 carbon position are found to be
for isomerization of light naphtha. Unlike light naphtha favored over the ZSM-22-type zeolite whereas branching at
isomerization, long-chain paraffin isomerization needs to center positions are favored over the ZSM-23 type of zeolite
be controlled to an optimal level to achieve the desired VI [65]. Such a trend is noticed over Pt (0.3 wt %)/ZSM-22
and pour point, respectively. Furthermore, the position of in the hydroisomerization of long-chain n-paraffins in the
branching and the branching index are found to be key for range of n-decane to n-tetracosane. The maximum yield of
the production of lube oil with high viscosity index and total isomers (monobranched and multibranched isomers)
the desired pour point, respectively. The branching at the between 77 and 90 wt % is noticed over ZSM-22 zeolite
near-terminal position of long-chain paraffins vis-à-vis at with a maximum yield of monobranched isomers obtained
near-center positions is reported to have significant effect, with the different n-paraffins in the range of 55–80 wt %.
especially on VI [59]. Skeletal isomerization has been investigated on Pt/ZSM-23.
Thus, to meet such stringent criteria, it is of the utmost Attempts have also been made to fine-tune the acidity level
importance to use a catalyst having fine-tuned balance of such zeolites. Accordingly, the acidity level is fine-tuned
between metal-acid functions to achieve the highest isomer by means of steam deactivation for Pt (0.6 wt %)/ZSM-48,
selectivity and yield at the lowest possible reaction temper- ZSM-22, and ZSM-23 catalysts for the hydroisomerization
ature. To develop such a catalyst system, focused attempts of n-decane. The tests showed that by steaming, the maximum
have been made to understand zeolite, SZ, and mesoporous isomerization yield of Pt/ZSM-48, ZSM-22, and ZSM-23
materials in terms of their structure and acidity level for catalyst can be increased from 78 to 90, 50 to 68, and 50 to
improving the isomerization selectivity with an increase in 72 wt %, respectively [64].
conversion. Excellent reviews covering the aforementioned It is interesting to note that Pt/ZSM-23 is reported to
aspects are available in the literature. The following subsec- favor monobranching near the center of the molecule. Such a
tions present a brief overview of such efforts. branching pattern is reported to favor an increase in VI [59].
In view of this, MTT zeolite can be judged to have an edge
7.3.2.1 Zeolites (e.g., ZSM-23, ZSM-22, and over TON-type zeolite for production of lube oil with high VI.
ZSM-48) In view of this, patent literature extensively covers
Among the various zeolite frameworks, medium-pore zeolites MTT- and TON-type zeolite-based catalysts for lube oil
have gained considerable attention for isomerization of production. It also covers small-crystal MTT and the TON-
long-chain paraffins. This is primarily because medium- MTT intergrowth topology framework for such application
pore zeolites favor the formation of methyl branchings in [66,67]. The small zeolite crystals, on the basis of the pore
the linear aliphatic hydrocarbon chains because of their mouth catalysis concept, are expected to offer higher external
restricted pore geometry. In other words, if the pore opening surface area and are anticipated to favor isomerization
of zeolite is small enough to restrict the larger isoparaffins with increased yield and selectivity. On similar lines, the
from reacting at the acidic sites inside of the pore, the catalyst morphology of potential zeolite crystals is anticipated to
will show good selectivity for converting n-paraffins. The play a critical role in improving the catalyst performance
unique selectivity of medium-pore zeolite is ascribed to the in the isomerization process. It is noteworthy that patent
pore mouth/key-lock catalysis mechanism [60,61]. In gen- literature indicates the improved performance of zeolite
eral, methyl branching increases with the decreasing pore crystals with slab morphology with respect to conversion
width of the zeolite, whereas ethyl and propyl branched and selectivity under isomerization conditions.
isomers that are more susceptible to hydrocracking are
obtained from wide pore openings and large cavities [62]. 7.3.2.2 Silicoaluminophosphate Molecular
On the basis of the pore mouth/key-lock catalysis Sieves (e.g., SAPO-11, SAPO-31, and SAPO-41)
mechanism, it is apparent that the potential medium-pore Silicoaluminophosphate (SAPO) molecular sieves generally
zeolite should have following characteristics for selective have a lower acidity than zeolites. Among SAPO molecu-
hydroisomerization: lar sieves, medium-pore SAPOs (SAPO-11, SAPO-31, and
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166 Petroleum Refining and Natural Gas Processing

SAPO-41) have been envisaged to be suitable for constituting have 10-membered ring one-dimensional elliptical channels
catalysts that manifest better performance for long-chain that are effective for hydroconversion because of their
hydrocarbon isomerization [68]. The main SAPO feature shape selectivity, as described earlier. However, SAPO-41
is that it results in relatively low-branched isoparaffins [69]. is reported to be more active than SAPO-11 because of its
The SAPO framework is created by Si substitution into slightly larger pore size, which in turn is expected to offer less
the AlPO4 framework. There are two mechanisms for this diffusion constraints for reacting molecules as compared
substitution: with SAPO-11 [70–73].
1. SM2: One Si substitutes for one P, and
2. SM3: Two Si substitute for one P and one Al. 7.3.2.3 Mesoporous Materials (MCM-41,
When Si substitutes P, Brönsted acid sites are formed, AlMCM-41)
whereas if P and Al are simultaneously replaced by two Si Since the discovery of the new class of mesoporous materials
atoms, the tetrahedral framework remains neutral [11,12]. such as MCM-41 in 1992, there has been a growing interest
Among the potential SAPO frameworks, SAPO-11 with in their potential catalytic applications [75]. Because of their
AEL-type topology is selective for producing monobranched relatively mild acid sites and the possibility to vary the Si/Al
alkanes during the hydroisomerization of long-chain normal ratio over a wide range without significant changes in pore
paraffins. Medium-pore SAPO-11 was initially used by M/s structure, these materials are very attractive model catalysts

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Chevron in their isodewaxing process for the selective isom- for the transformation of bulky compounds, especially for
erization process of high-boiling waxes for the production the hydroisomerization of long-chain n-paraffins [76–78].
of high-viscosity lube oils. Thus, n-decane hydroconversion on bifunctional catalysts
The hydroisomerization of n-C14 over Pt (0.4 wt. %)/ comprising Pt, Pd, and bimetallic Pt–Pd supported on an
SAPO-11 catalyst in a fixed-bed reactor shows high isomeriza- Al-MCM-41 (Si/Al = 23) has been investigated [76–78].
tion selectivity. Over this catalyst, conversion of n-heptane The results of this investigation are shown in Table 7.6.
presented a similar trend, but the values were lower than Accordingly, the catalytic activity of all catalysts containing
those of n-tetradecane hydroisomerization at the same bimetallic clusters is increased in comparison with the values
experimental conditions. As for the isomerization products, of monometallic catalysts [77].
the maximum yield of feed isomers was 55 % for n-heptane On the other hand, Pd (0.35 wt %)/AlMCM-41 catalyst
hydroconversion. A maximum yield of more than 80 % at 623 K in the hydroisomerization of n-tridecane is found
was obtained for n-C14 hydroconversion. Also, SAPO-11- to have good selectivity with a lowering framework Si/Al
based catalyst when evaluated for hydroisomerization of ratio (Table 7.7).
n-hexane, n-octane, and n-hexadecane showed the least The observed trend suggests more critical balance
activity for n-hexane conversion and is the most reactive between the acid function of MCM-41 and the metal function
for n-hexadecane. This result shows that the SAPO catalysts for simultaneous increase in isomer selectivity and selectivity
are adequate only for long-chain n-paraffins [70–73]. The at the lowest possible temperature.
performance of Pt/SAPO-11 is enhanced with doping of tin.
Isomerization of n-dodecane over Pt-Sn/SAPO-11 catalysts 7.3.2.4 Tungstate-Promoted Zirconia
showed more than 90 % n-dodecane conversion but only (WOx-ZrO2)
85 % isomerization selectivity at 87 % n-dodecane conversion Anion-modified metal oxides, such as SZ (SO4/ZrO2) and
over Pt/SAPO-11 has been obtained. The results indicate tungstated zirconia (WO3/ZrO2), have been found to catalyze
that, on SAPO-11 base catalysts, n-dodecane (a long-chain
n-paraffin) can intensively isomerize with very limited
cracking. The better hydroisomerization performance of
Table 7.6—Maximum Isomer Yields of Pt,
the former catalyst has been attributed to the addition of
Pd, and Pt-Pd/AlMCM-41 Catalysts in the
tin to the metallic catalyst composition [70–73]. Like other
Hydroisomerization of n-Decane
zeolite catalysts, the performance of SAPO-based catalysts is Maximum
reported to be influenced by metal dispersion and the sur- Conversion Isomer Yield
face area of the catalyst. To achieve higher acidity, attempts Metal Compound Tmax (K) (wt %) (wt %)
have been made to incorporate Si by the SM2 mechanism. 0.5 wt % Pt 628 81 53.8
Such mechanism prevails when SAPO-11 is prepared using
the water-cetyltrimehtlammonium bromide-butanol phase 0.27 wt % Pd 653 74.3 54.5
[74]. The crystallized SAPO-11 framework is reported to 0.375 wt % 593 77.4 44
have more Brönsted acid sites and smaller crystallite size. Pt–0.068 wt % Pd
Such SAPO-11 support is found to be more active than
0.25 wt % 573 58.6 38.2
the conventionally prepared framework [74]. SAPO-11 with
Pt–0.135 wt % Pd
small crystal size is expected to decrease the effect of dif-
fusion; carbenium intermediates thus easily desorb from 0.125 wt % 583 69.6 37.3
acid sites so that further isomerization and cracking are Pt–0.203 wt % Pd
expected to decrease. 0.125 wt % 603 82.4 32.4
Among SAPO-11, SAPO-31, and SAPO-41 with identical Pt–0.068 wt % Pd
acid strength, the hydroconversion activity for n-octane
0.5 wt % 583 73.3 48.9
is found to decrease in the order SAPO-41 > SAPO-11 >
Pt–0.27 wt % Pd
SAPO-31. The low activity of SAPO-31 is ascribed to its frame-
work structure (i.e., it has 12-membered ring one-dimensional Reaction conditions: PH2 = 1 MPa, Pn-C10 = 10 kPa, H2/n-C10 mole ratio = 100,
W/F = 400 g×h/mol.
circular channel). On the other hand, SAPO-41 and SAPO-11
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Chapter 7 n Hydroisomerization of Paraffins in Light Naphthas and Lube Oils 167

dispersion of Pt and in turn demonstrates low activity for

Table 7.7—The Results of the isomerization reaction.
Hydroisomerization of n-C13 over
Different Pd/AlMCM-41 Catalysts [78]
7.3.2.5 Commercial Catalysts for
Total Acid n-C13 i-C13 Hydroisomerization of Lube Oil
Amount Si/Al Conversion Selectivity The advances made in understanding the role of medium-pore
(mmol/g) Ratio (wt %) (wt %) molecular sieve support in controlling the bulk properties
0.135 100 59.3 86.4 of lube oil (i.e., VI and pour point) have added impetus
for commercial catalyst development. On the basis of the
0.161 75 59.8 88.7
reported literature data, commercial catalyst could be derived
0.164 50 60.2 86.5 based on AEL (SAPO-11), TON (ZSM-22), and MTT (ZSM-23)
molecular sieve. It is worthwhile to note that ease of zeolite
0.198 25 59.5 91.8
scale-up in terms of cost of its synthesis with desired crystal
Reaction conditions: T = 623 K, Pt = 3.5 MPa, H2/n-C13 = 600, WHSV = 1.5 h–1 morphology, fine tuning of textural properties, and crystallite
size drives the commercial utilization of molecular sieve in
hydrocarbon conversions under mild conditions. These strong lube oil production. On the basis of the patent literature, the
solid acids are environmentally benign and regenerable. cost of the structure-directing agent (viz. diquat-n type) for
Butane isomerization over SZ has attracted considerable synthesis of the slab-shaped morphology of zeolite crystals
attention because isobutane is the precursor to methyl-t-butyl can be envisaged to be a bottleneck in determining the cost
ether. Metal-promoted SZ is effective for isomerization of of zeolite for catalyst development.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

short-chain paraffins and for hydrocracking of long-chain The first-generation catalyst based on SAPO-11 was
paraffins including waxes and polyolefins [9]. However, loss developed by M/s Chevron in the early 1990s. However, it
of activity due to coke formation and sulfur loss, especially was soon phased out because of its poor activity, higher
under reducing conditions, is an obstacle to certain practical operation temperature, high hydrogen/feed ratio, and lower
uses of SZ. Moreover, high isomerization selectivity is difficult isomerization selectivity, especially to meet VI demand.
to achieve over SZ because the chain length increases, even Today, the commercial hydroisomerization-assisted lube oil
at low conversions. Studies of tungstate-modified zirconia production process uses a catalyst that offers the following
indicate that it is more stable than SZ and is promising for main features:
hydroisomerization of high-molecular-weight linear paraffins • High selectivity for isomerization,
[79–84]. • Selective branching positions to meet the VI demand,
The performance of Pt (0.5 wt %)/WO3/ZrO2 catalyst for • Comparable isomer yields vis-à-vis conversion level,
the hydroisomerization of n-hexadecane in a trickle-bed • Increased catalyst life,
continuous reactor demonstrated high activity and selectivity • Minimum hydrogen/feed ratio, and
for hydroisomerization of long-chain n-paraffins [79]. The • Minimum VI drop between feed and product to produce
optimal range of tungsten loading to achieve high isomeriza- premium lube oil.
tion selectivity at high n-hexadecane conversion is found to In view of this, M/s Chevron has reported high potential
be between 6.5 and 8 wt % [79]. The comparison between Pt for SSZ-32 zeolite in patent literature. Likewise, M/s Exxon-
(0.5 wt %)-/SO4/ZrO2 and /WO3/ZrO2 (Table 7.8) shows that Mobil has extensively covered ZSM-23, ZSM-22, and ZSM-48
Pt (0.5 wt %)/SO4/ZrO2 catalyst converts 80 % of converted in their patents.
n-hexadecane to short-chain paraffins when operated at On the basis of the progress made on the aforementioned
423 K because it was very active and was not stable at high catalyst front, commercial processes have been developed
temperatures in the presence of hydrogen. On the other for the hydroisomerization of gasoline and lube dewaxing
hand, Pt (0.5 wt %)/WO3/ZrO2 with a comparable n-C16 to improve product quality. In the following sections, these
conversion to that of Pt/SO4/ZrO2 favored the formation of commercial hydroisomerization processes are discussed.
many more C16 isomer products [85].
In view of the observed trend, the combination of 7.4 Process for Gasoline Octane
sulfate and tungstate species is expected to play a vital role Boosting
in controlling the surface acidity and acid density for zirco- The isomerization of low-molecular-weight paraffins has
nia surface. However, metal function for Pt/WZR is found to been commercially practiced for many years. During the
be dependent on treatment conditions. The oxidation step 1930s, World War II prompted the development of the
during catalyst preparation is found to prevent the forma- laboratory processes into full-scale commercial units to
tion of tungsten-Pt species, which commonly leads to low meet the demand for isobutene, which was necessary for

Table 7.8—Hydroisomerization of n-C16 on Pt (0.5 wt %)/SO4/ZrO2 and Pt (0.5 wt %)/WO3/ZrO2

(6.5 wt % W)
Catalyst Reaction Temperature (K) n-C16 Conversion (wt %) i-C16 Selectivity (wt %) i-C16 Yield (wt %)

Pt (0.5 wt %)/SO4/ZrO2 423 76.7 19.8 15.2

Pt (0.5 wt %)/WO3/ZrO2 503 85.9 83.1 71.4

Reaction conditions: Pt = 300 psig, WHSV = 1 h , H2/n-C16 mole ratio = 2 –1

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168 Petroleum Refining and Natural Gas Processing

the manufacturing of large amounts of alkylate. Today, to remove naphthenes and moisture, especially when Pt/
the interest in isomerization is especially focused on the Cl-alumina-based catalyst is used for isomerization. On the
upgrading of fractions of light naphtha for their use as motor other hand, Pt/zeolite catalyst is more tolerant to such feed
gasoline components because of stringent environmental impurities [4]. Typical process flow diagrams that are based
norms. on alumina and zeolite catalysts are shown in Figure 7.4.
The first hydroisomerisation unit was introduced in Such processes can be performed either in once-through
1953 by UOP, followed in 1965 by the first BP unit. In or recycle mode. A typical once-through mode of operation
1970, the first Shell hydroisomerisation (HYSOMER) unit minimizes hydrogen consumption, suppresses coking, and
was started up. The following major hydroisomerization often limits product RONs up to 84, whereas recycle-mode
processes are presently commercially available for C5/C6 operation helps to achieve RONs up to 92 (Table 7.10).
isomerization [4]: The once-through process is generally performed at low
• SHELL HYSOMER; temperatures by taking advantage of thermodynamics
• Axens ISOSORB and HEXSORB; and (Section 7.3) in the presence of Pt/Cl-alumina catalyst to
• UOP PENEX, Par-Isom, and TIP. achieve the desired product RON [4]. The recycle mode
The catalysts used in these processes are listed in of operation can be performed using fractionation- and
Table 7.9 [4]. adsorptive-separation-based recycling options to improve
The typical product RONs obtained in a once-through the isomerate yields.
process using these catalysts are depicted in Figure 7.3 [48]. The recycle-mode operation with adsorptive separa-
All of these processes take place in the vapor phase on tion uses a molecular sieve to separate isoparaffins from
a fixed-bed catalyst containing Pt on a solid carrier. These n-paraffins on the basis of a shape-selective separation
processes are performed in the presence of hydrogen to principle. Thus, the separated fraction of n-paraffins (C5 and
suppress dehydrogenation and coking so as to improve C6) is again recycled back to the isomerization reactor along
catalyst life and its deactivation. The process temperature with feed to improve the isomerate yield. Likewise, the
usually governs the cycle life for such catalysts. High process recycle option by fractionation is performed by means of
temperature generally increases the processing severity, distillation to improve the product RON.
which could lead to hydrocracking. On the other hand, The molecular sieve recycle option was commercial-
low temperature, moderate hydrogen partial pressure, and ized by M/s UOP in 1975 with the introduction of the total
low space velocity are found to promote long cycle lengths. isomerization process (TIP), in which the isomerization is
Furthermore, increased naphthene and moisture content completely integrated with a molecular sieve separation
in the feed often impart an irreversible inhibitor effect. process or the naphtha IsoSiv process. Recently, both of the
Thus, feed pretreatment is performed before isomerization recycle options were coupled by M/s IFP, which has led to
the development of two processes: IPSORB and HEXSORB.
IPSORB typically integrates the distillation and molecular
Table 7.9—Commercial Catalysts Used for sieve adsorption section: a deisopentanizer and molecu-
Light Naphtha Isomerization lar sieve desorption with isopentane for IPSORB. On similar
Catalyst Catalyst Type Licensor lines, a deisohexanizer with methyl pentane desorption is
coupled with distillation for HEXSORB.
IFP IS 612, 614A, ATIS-2L Pt/Al2O3 IFP
In view of the above, the important features of the
IFP–IS 632, IP-632 Pt-mordenite IFP aforementioned light naphtha isomerization processes are
HYSOMER process:
UOP I-7 Pt-zeolite UOP
• Process temperature: 505–558 K
UOP I-8 Pt/Al2O3 UOP • Pressure: 13–30 bar
• Isomerate content in product relative to feed: 97 % or
Hysopar Sulfated zirconia Süd-Chemie
better
• Catalyst: Pt/zeolite (mordenite), stable and regenerable
90 • RON upgrade: Between 8 and 10 points, depending on
feedstock quality.
88
The HYSOMER process can be integrated with a cata-
86 lytic reformer, resulting in substantial equipment savings,
84 or with iso/normal separation processes, which allows for
82 a complete conversion of pentane/hexane mixtures into
RON

isoparaffin mixtures.
80
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

TIP process [4]: This process uses

78 • Molecular sieve adsorbent-based recycle option to
76 upgrade product RON;
74 • Zeolite catalyst with improved sulfur or water tolerance,
or both, which allows in situ regeneration with extended
72
life up to 10 years or more; and
70 • Similar operating conditions in isomerization and the
Zeolite Metal oxide Cl/Alumina
molecular sieve separation section, thereby eliminating
Figure 7.3—Typical product RONs obtained with various the costs associated with cooling, purifying, and reheat-
catalysts. ing the recycled normal paraffins.

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Chapter 7 n Hydroisomerization of Paraffins in Light Naphthas and Lube Oils 169

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 7.4—Flow diagram for an isomerization process based on (a) Pt/Cl--alumina and (b) Pt/zeolite catalysts.

A typical process flow diagram for TIP is provided in Continuous efforts are being made to improve the
Figure 7.5. hydroisomerization catalyst and processes based on it so
IPSORB and HEXSORB processes [4]: The combi- as to meet the challenges to handle feed variation. One of
nation of distillation and molecular-sieve-based separation these efforts led to the development of a successful process
offers the following important and unique features: called Par-Isom by M/s UOP in 1996 [48]. This process uses
• To lower the n-paraffin content in the isomerate, and Pt/SZ catalyst.
• To offer efficient separation and better efficiency in the The flow diagram of the Par-Isom process is depicted
unconverted n-paraffin recycle. in Figure 7.6 [47]. A proprietary catalyst LPI-100 composed
of Pt/SO42–/ZrO2 with excellent sulfur- and water-tolerant
limits is used in this process. The LPI-100 catalyst is fully
regenerable using the simple oxidation procedure. It also
Table 7.10—RONs Achieved with Different allows for lower reaction temperature operation and higher
Processes space velocity than the zeolitic catalyst process. This char-
Process Catalyst acteristic has been claimed to reduce the capital investment
and lower the operation cost.
Cl/alumina Zeolite R1 = Isomerization reactor
Once-through 84 79 D1 = Desorption unit
A1 = Adsorption unit
IPSORB (IFP) 90 88
S1 = stabilization
HEXSORB (IFP) 92 90 RCY1 = Recycle: unconverted hydrogen and n-paraffins
The important features for various isomerization
TIP (UOP) – 89
processes licensed by leading technology licensors that

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170 Petroleum Refining and Natural Gas Processing

Figure 7.5—Process flow diagram for TIP.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 7.6—Process flow diagram for Par-Isom process.

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Chapter 7 n Hydroisomerization of Paraffins in Light Naphthas and Lube Oils 171

Table 7.11—Isomerization Process Features

Chlorinated Alumina Metal Oxide (Zirconia) Common Zeolite
Catalyst—Process (Penex Process) (Par-Isom Process) (HYSOMER Process) Modern Zeolite

Process licensor M/s UOP M/s UOP M/s Shell M/s Axens (IFP)

Feedstock conditions

Feedstock type C5/C6 C5/C6 C5/C6 C5/C6

Sulfur (ppm) None <20 <20 <200

Water (ppm) None <20 <20 <200

Aromatics/benzene (%) <2 <2 <2 <10

C7+ (%) <2 <2 <2 <5

Feed-product treatment

HDS Yes Yes Yes Optional

Sulfur guard Yes Optional Optional No

Feed dryer Yes Optional Optional No

Hydrogen dryer Yes Optional Optional No

Effluent guard system Yes No No No

Typical process conditions

Temperature (K) 403–423 453–483 533–553 523–553

Pressure (barg) 15–35 15–35 15–35 15–35

Liquid hourly space velocity: (h ) –1

1–3 1–3 1–3 1–3

H2/HC molar ratio 1–2 1–2 1–2 1–1.5

Typical isomerate properties

i-C5/C5-ratioa 68–72 65–71 60–65 63–67

2,2-DMB/C6-ratio a
21 20.5 16 19

Isomerate yield (%)

b
96+ 96+ 95+ 96+

Isomerate octane b
Up to 94 Up to 94 Up to 94 Up to 94
Reactor outlet.
a

Unit outlet.
b

are based on different catalyst systems are summarized in the solvent extraction route using solvents such as pentane
the Table 7.11 [48]. followed by removal of aromatics by means of solvents
viz. furfural, n-methyl pyrrolidone (NMP), or pyridine and
7.5 Process for Base Oil Production other impurities such as oxygenates, nitrogen compounds,
Since 1890, petroleum-based lubricants are used at the auto- and color bodies via clay and acid treatment of base oil
motive and industrial level [1,2]. However, as the demand for feedstock to obtain the desired lube oils. However, such a
automobiles grew, so did the demand for better lubricants. route often led to yield loss and was more suited for the pro-
This has led to process improvement in base oil production. duction of Group I lube oil base stocks. Moreover, this route
The typical process developmental steps involved in lube oil posed a serious problem for the disposal of waste clay/acid.
production are depicted and described below. A major breakthrough in base oil production was
Three popular processing routes that were used in achieved in the 1950s by introducing the hydroprocessing
early times (Figure 7.7) were solvent extraction/dewaxing, route [3]. Such a route was introduced to remove impurities,
clay treating, and acid treating. These processes were pri- mainly unsaturated and aromatic hydrocarbons, via the
marily aimed at removing asphaltenes and wax by means of hydrofinishing route (Figure 7.8).
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

VGO-Solvent DAO-Solvent Clay / acid

deasphalting Dewaxing treatment Product

Figure 7.7—Typical process block diagram used during pre-1950s period for lube oil production.

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172 Petroleum Refining and Natural Gas Processing

VGO-Solvent DAO-Solvent
deasphalting Dewaxing Hydrofinishing Product

Figure 7.8—Typical process block diagram used during the 1950s for lube oil production.

With an increased demand for high-performance lube The modern hydroisomerization process licensed by
oil with high VI, the lube oil manufacturing process was M/s Chevron under the name ISODEWAXING® gained
revolutionized by replacing the solvent dewaxing route with rapid acceptance since its introduction in 1993. In fact,
the catalytic dewaxing route that is based on catalytic crack- approximately one third of all base oils manufactured in
ing (Figure 7.9). This technology was commercialized in the North America are now manufactured using this process.
1970s by M/s Shell to manufacture extra high-VI base oils A similar trend can also be seen in the rest of the world.
in Europe. M/s Exxon and others built similar plants in the M/s Chevron has integrated the all-hydroprocessing routes
1990s. Likewise, M/s Mobil used catalytic dewaxing in place (i.e., isocracking, isodewaxing, and hydrofinishing) for
of solvent dewaxing, but they still coupled it with solvent making high-purity Group II and Group III base oils—base
extraction to manufacture conventional neutral oils [20]. oils that are as clear as water (Figure 7.11).
In the early 1990s, the need for higher quality lubri- The general operating conditions for ISODEWAXING®
cating oils prompted many lubricant producers to look are summarized as follows [3,86–90]:
to hydroprocessing as a means to upgrade marginal feeds • Hydrogen partial pressure (psi): 500–2500

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
to quality lube stocks and to further upgrade stocks to • Liquid hourly space velocity: 0.3–1.5
near-synthetic quality. Within this area, the primary focus • Temperature (K): 588–644
was to obtain product yield and quality that exceed those • Hydrogen rate (SCF/barrel feed): Not disclosed
obtained via solvent dewaxing and catalytic dewaxing. This • Hydrogen consumption (SCFB): 100–500
has been the principal motivation for the development of M/s ExxonMobil also added to this trend by commer-
several bifunctional, metal-loaded, molecular-sieve-based cializing an all-hydroprocessed route for Group II base oil
hydroisomerization catalysts that led to the evolution of all- production MSDW™, which they installed in their Jurong
hydroprocessing lube dewaxing technologies (Figure 7.10), refinery in Singapore in 1997. MSDWTM converts waxy
including Chevron’s isodewaxing and Exxon-Mobil’s selective oils and raffinates to conventional or ultra-low pour-point
dewaxing (MSDW) and wax isomerization (MWI) processes. (≤233 K) base oils and provides a serious jump in oil VI over
In 1993, this modern wax hydroisomerization process hydroprocessed feed stocks. Base oils made from catalytic
was commercialized by M/s Chevron. This was an improve- dewaxing exhibit improved cold-cranking performance
ment over earlier catalytic dewaxing because the pour point compared with solvent dewaxed oils of similar viscosity.
of the base oil was lowered by isomerizing (reshaping) the This is because of the unique effect of the shape-selective
n-paraffins and other molecules with waxy long chains into catalyst, which isomerizes n-paraffins rather than physically
very desirable branched compounds (isoparaffins) with removing the wider spectrum high-melting-point waxes.
superior lubricating qualities rather than cracking them The MSDWTM process also uses propriety zeolites and is
away. Hydroisomerization was also an improvement over claimed to be superior to Mobil’s MLDWTM process, which
the earlier wax hydroisomerization technology because it uses ZSM-5-based catalyst, which selectively cracks paraffins
eliminated the subsequent solvent dewaxing step, which leading to lower yields [89]. The improvement in product
was a requirement for earlier generation wax isomeriza- quality with the MSDW process as compared to solvent
tion technologies to achieve adequate yield at standard dewaxing for hydrocracked light-neutral lube oil feedstock
pour points. Modern wax hydroisomerization makes is shown in Figures 7.12 and 7.13 [90].
products with exceptional purity and stability because Thus, advantages claimed with MSDWTM are as follows:
of the extremely high degree of saturation. They are very • High yields on all viscosity grades,
distinctive because, unlike other base oils, they typically • Better cold-cranking in base oils, and
have no color [86,87]. In view of the above, it is imperative • Highly flexible process.
to note that process improvement in lube oil production On similar lines, M/s ExxonMobil introduced a pro-
has changed over from physical separation to chemical cess called MWI for converting wax-rich streams, such
transformation. as slack wax, into very high-VI lubes. This process uses a

Catalytic dewaxing
VGO- Hydrofinishing Product
+solvent extraction
Hydrotreating

Figure 7.9—Typical process block diagram used during the 1970s for lube oil production.

VGO- Hydroisomerization
Hydrofinishing Product
Hydrotreating

Figure 7.10—Typical process block diagram used during the 1990s for lube oil production.
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Chapter 7 n Hydroisomerization of Paraffins in Light Naphthas and Lube Oils 173

Figure 7.11—Process flow diagram for the ISODEWAXING® process.

100 120

118
95 116
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

114
Yield, wt %

90 112

110
VI

85 108

106
80 104 MSDW-1
MSDW-2
MSDW-2
MSDW-1 102 Solvent dewaxing
Solvent dewaxing
75 100
250 260 270 280 230 240 230 240 250 260 270 280
Pour point, (K) Pour point, (K)
Figure 7.12—Variation for Lube oil yield as a function of pour Figure 7.13—Variation for Lube oil Viscosity Index (VI) as a
point. function of pour point.

solvent dewaxing step to obtain high-quality lubes with very

bifunctional metal-zeolite catalyst to saturate residual low pour points and high VIs. The MWI catalyst system can
aromatics, isomerizes paraffins, and opens some naphthene process a wide range of feedstock [89,90].
rings. A solvent dewaxing is used downstream of the MWI
unit to remove residual wax in the product. M/s ExxonMobil 7.6 Future Challenges and Opportunities
recently announced an improved version of MWI in which In view of the significant aforementioned improvements
very selective catalytic isomerization is used in place of the in catalyst and process developments, it is important to
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174 Petroleum Refining and Natural Gas Processing

note the major concerns and future challenges of the Pt/zeolite, and Pt/ Pt/SO42–/ZrO2 have been commercially
hydroisomerization catalyst and conversion processes. exploited for light naphtha isomerization whereas medium-
As illustrated in Section 7.3, catalyst performance for pore zeolites with TON/MTT topology are found to be an
light alkane isomerization is susceptible to the naphthene ideal choice for lube oil isomerization.
content in the feed. The processes practiced commercially On the basis of the aforementioned catalyst systems,
in once-through mode often operate with restriction on the hydroisomerization processes have evolved. All of these
naphthene content in the feedstock. Therefore, a catalyst processes are performed in a fixed-bed reactor. The pro-
system to handle higher naphthene content needs to be cesses for light naphtha isomerization have seen operational
developed. In this context, zeolite membrane reactors changeover from once-through to recycle mode to achieve
could offer clear advantages in terms of the handling of RONs over 90. In the recycle mode, unconverted n-paraffins
feed quality, improved yield, and energy savings due to the in the single pass are separated either through distillation
exceptional properties of zeolite membranes, which include or molecular sieve separation from isomerized products.
their (1) size- and shape-selective separation behavior, Likewise, process steps for lube oil production have changed
(2) their thermal and chemical stability, and (3) the ability over from physical wax separation to its chemical trans-
to couple the discrimination between molecules to catalytic formation, thereby leading to the production of improved
conversion. However, it is clear that to capitalize on these yields and better quality lubricant base stocks. Such step
benefits, a substantial reduction in membrane module cost change has offered a platform to either integrate or replace
and further improvements on the integrity (selectivity and the solvent dewaxing processes for production of Grade II/
permeability) of the molecular sieve films to facilitate a III base oils. However, catalyst limitations in terms of its
reduction in surface area requirements are mandatory for conversion, isomerization selectivity, and maximization of
further commercial development. throughput still demand the search for new catalysts and
On the other hand, the performance of the current process improvements to produce high-quality fuels and
lube oil catalyst is often limited because of isomerization lubricants.
selectivity, throughput, and feed impurities. Thus, it is
important to further fine-tune lube oil dewaxing catalysts Acknowledgments
in terms of The authors are thankful to the management of Bharat
• Increased conversion level, Petroleum Corporation Limited for granting permission to
• Increased isomer selectivity, and publish this chapter.
• Feedstock flexibility and throughput (expansion of
LHSV operation). References
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176 Petroleum Refining and Natural Gas Processing

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8
Heavy-Oil Processing
Semih Eser1 and Jose Guitian2

8.1 Definitions and Sources of Heavy Oils According to the EIA, total oil consumption will
8.1.1 Definition of Heavy Oils increase from 85 million bbl/day in 2006 to 107 million
There are various ways to characterize crude oil. Most of bbl/day to in 2030, whereas the total heavy-oil production
them are based on API gravity and viscosity at field condi- will increase from 8 million bbl/day in 2006 to 16 million
tions. Table 8.1 gives a classification that is used for the bbl/day, and the extra-heavy-oil + bitumen production will
purposes of this chapter. increase from 2 million bbl/day in 2006 to 6 million bbl/
Oils with an API gravity between 22º and 10° API are day in 2030.
considered as heavy crude. Extra-heavy crudes are defined Currently, a large part of the heavy oil produced in Ven-
as oils with an API gravity of <10ºAPI and a viscosity of ezuela and Canada is upgraded to produce a light synthetic
<10,000 cSt and that are mobile at initial reservoir condi- crude oil (SCO) of high quality or diluents to mix with the
tions. These types of crude can be found in the Orinoco Oil untreated heavy crude for transportation to the markets
Belt in Venezuela, Colombia, Argentina, Peru, and Califor- because of the lack of light crudes or naphtha for dilution.
nia in the United States. Bitumens are characterized by an This type of crude is called “Synbit” because it consists of a
API gravity of <10ºAPI that are immobile at reservoir condi- mixture of synthetic distillates produced by upgrading the
tions. These types of crude are also called “oil sands” or “tar virgin heavy crude. In the future, the scarcity of the diluents
sands” such as the Canadian oil sands. More information will grow much larger. Therefore, most of the heavy crude
and data on different kinds of heavy oils can be found in will need to be commercialized as SCO.
the literature [1,2].
8.2 Analysis of Heavy Oil
8.1.2 Sources of Heavy Crudes As the crude oil base for worldwide refining gets heavier,
Heavy oil and bitumen are widely distributed worldwide. the analysis of the heavy oils or the heavy (or high-boiling)
They have been found in every continent except Antarctica, components of crude oil stocks has become increasingly
as indicated in Figure 8.1. The total estimated resources of important. To optimize the selection of upgrading processes,
heavy crude and bitumen are 3.3 trillion barrels, and 2.6 tril- processing conditions, and distribution to lighter products,
lion barrels, respectively. According to the U.S. Department it has become crucial to obtain analytical data on heavy oils
of Energy’s (DOE) Energy Information Administration (EIA) beyond the conventional characterization techniques, such as
[3] and the U.S. Geological Survey (USGS) [4], the potential API gravity, sulfur content, viscosity, and simple fractionation
recoverable reserves are on the order of 1 trillion barrels that by distillation and/or solvent extraction. Several publications
are in the same order of magnitude as the proven reserves of [5–9] have clearly articulated this need along with the associ-
the world’s conventional (medium and light) crude oils. ated challenges and reviewed the use of different methods for
Most of the heavy crude and bitumen produced today the analysis of heavy oils. Because of the extremely complex
come mainly from North and South America: Canada, constitution of heavy oils, it is often necessary to separate the
Venezuela, Mexico, the United States, Brazil, and Ecuador. oil samples into fractions that can be more easily analyzed.
The Canadian oil sands (bitumen) and the Venezuela Ori- The recent advances in the analysis of heavy oils stem from
noco Oil Belt (heavy crude) are the largest accumulations the improvements of instrumental techniques that enable
of nonconventional oil reserves in the world. The Western better fractionation into compound groups and increased
Hemisphere has 69 % of the world’s heavy-oil reserves and resolution of the molecular species in the separated fractions.
63 % of the natural bitumen resources. In contrast, the This section provides an overview of analytical techniques
Eastern Hemisphere has approximately 85 % of the world’s that are commonly used to characterize heavy oils.
light oil reserves. Because the volatility of the heavy-oil samples is low,
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Most heavy-oil reserves have not been massively gas chromatography applies only to analyze the compo-
extracted until recent times because of higher production, nents separated and concentrated using various preparative
transport, and processing costs of this type of crude. Declin- fractionation techniques. However, liquid chromatogra-
ing availability of conventional crude reserves has sparked phy is commonly used in a preparative scheme for initial
recent interest in processing and converting the heavier fractionation of the samples for further analysis or in an
crudes and bitumen. Major oil companies have considered analytical mode for speciation of the separated fractions.
the heavier crudes as replacement for light and medium Barman et al. [10] and Sharma et al. [11] have reviewed the
crudes. The projections for estimated heavy-oil and bitu- chromatographic techniques used for analyzing petroleum
men production are shown in Figure 8.2. and related products.
1
Pennsylvania State University, University Park, PA, USA
2
Repsol S. A., Madrid, Spain
177
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178 Petroleum Refining and Natural Gas Processing

Table 8.1—Classification of Oils and Definition of Heavy Oil, Extra-Heavy Oil, and Bitumen
Type of Oil API Gravity Viscosity in the Reservoir Definition of Oil
Conventional Oil >45º Condensate

22–45º Medium-light crude

Nonconventional Oil 10–22º <10,000 cSt Heavy crude

Mobile at reservoir conditions

<10º <10,000 cSt Extra-heavy crude

Mobile at reservoir conditions

<10º >10,000 cSt Bitumen

Immobile at reservoir conditions

Figure 8.1—Heavy-oil and bitumen resources and their worldwide distribution [3].

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Figure 8.2—Projections of total oil consumption and total production of heavy-oil and extra-heavy-oil/bitumen production [3,4].

8.2.1 SARA Analysis s eparation scheme used in SARA analysis. In the first step,
One prominent application of liquid chromatography is the oil sample is mixed with an abundant quantity (typically
found in a frequently used SARA analysis that separates a 1:40 ratio) of light n-paraffin solvent (e.g., n-heptane) to
an oil sample into four fractions: saturates, aromatics, precipitate the insoluble materials (asphaltenes) that are
resins, and asphaltenes with respect to hydrocarbon types filtered and exhaustively washed with the same solvent
and the solubility/adsorption behavior of the constituent to make sure that all of the soluble material is recovered
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

species [12]. Figure 8.3 shows a schematic diagram of the and added to the soluble (maltene) fraction for further
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Chapter 8 n Heavy-Oil Processing 179

8.2.2 Hydrocarbon Group Analysis and

Molecular Speciation Techniques
In addition to being used as an effective separation tech-
nique in SARA analysis, HPLC has frequently been used
as an analytical tool to provide molecular speciation
of heavy oils or their maltene fractions [21–23]. More
recently, Saravanabhavan et al. [24] and Pasadakis et al.
[25] reported results on polycyclic aromatic hydrocarbon
(PAH) composition of a heavy gas oil sample using HPLC
with a photodiode array detector (PAD) to identify PAHs
on the basis of the ultraviolet (UV) spectra. The HPLC/
PAD results of Saravanabhavan et al. [24] compared well
with the gas chromatography (GC)/mass spectrometry
(MS) results on the same samples. Wang and Eser [26]
reported analysis of the PAH composition of fluid catalytic
cracking (FCC) decant oils by HPLC/PAD, HPLC in tandem
mass detectors (HPLC/MS/MS), and laser desorption mass
spectrometry (LDMS) to complement the GC/MS analysis
Figure 8.3—A schematic diagram of SARA analysis. to extend to higher-boiling compounds in the decant oils.
Figure 8.4 shows their HPLC/PAD (top) and HPLC/MS/MS
(bottom) chromatograms identifying the PAH ring systems
s eparation of the saturate, aromatic, and resin fraction and their alkyl-substituted analogs present in a decant oil.
using chromatography. In the chromatographic separation, In heavy crude oil samples, longer alkyl chains are associ-
one or two columns are used with a sequence of solvents to ated with the PAH ring systems. Hinkle et al. [27] reported
elute the adsorbed saturates, aromatics, and resins, respec- results from pyrolysis–molecular beam mass spectroscopy
tively. The saturate fraction consists of (n-, i-, and cyclo-) (Py-MBMS) analysis of heavy-oil samples and correlations
alkanes (i.e., paraffins and naphthenes) and the aromatic between MBMS data and the viscosity of heavy oils.
fraction contains aromatic hydrocarbons. The concept of TLC has been advocated as a preferred method to
SARA analysis was introduced in 1972 [12] and adopted HPLC to simultaneously separate the heavy oils into
as a standard method (ASTM D2007) [13] and has gone SARA fractions [12,28,29]. A coupled use of TLC with a
through many modifications. A principal driving force ﬂame ionization detector (FID) has enabled quantitative
for introducing these modifications has been to reduce analysis of the TLC fractions. Figure 8.5 shows the TLC/
the long time period and large quantities of samples and FID chromatograms of a crude oil and its fractions sepa-
solvents needed for the ASTM procedure. The variations rated by column chromatography to validate the TLC/FID
of SARA analysis have included using different n-paraffin technique. Rudzinski and Aminabhavi [30] reviewed the
solvents (n-pentane, n-hexane, and n-heptane), different use of supercritical fluid extraction (SFE), SFC, and liquid
oil-to-solvent ratios, different columns (e.g., clay-gel, silica, chromatography (LC) for fractionation and analysis of
alumina, and lately bonded phase columns), and differ- crude oil samples. Recently, Dutriez et al. [31] reported on
ent liquid chromatography methods [e.g., open column, extending the use of high-temperature two-dimensional
high-pressure liquid chromatography (HPLC), thin layer GC to analyze heavy-oil samples. The method they have
chromatography (TLC), and supercritical fluid chromatog- proposed was successful in analyzing a vacuum gas oil
raphy (SFC)]. The variations used in SARA analysis lead to (VGO) sample, but it needed improvement for analyzing
different results, including the differences in mass yields deasphalted oils (DAOs).
of the four fractions and their composition. Therefore, it is
important to be cognizant of all of the experimental param- 8.2.3 Characterization and Structure of
eters used for the analysis when comparing the reported Asphaltenes
results. Kaminski et al. have reviewed the chromatic meth- Simply defined as a solubility fraction of crude oil and
ods developed and validated for SARA analysis [13]. Several related materials (soluble in aromatic, or other strong
authors [14-18] have reported and compared results using solvents but insoluble in light liquid n-paraffins such as
different methodologies for SARA analysis of heavy oils. n-pentane, n-hexane, or n-heptane), the structure and
Hannisdal et al. [19] used near-infrared (NIR) and infrared properties of asphaltenes still pose controversies after
(IR) spectroscopy and Sastry et al. [20] used Fourier trans- more than a century of research. Including the heaviest
form infrared spectroscopy (FTIR) for analyzing the SARA and possibly the highest molecular weight compounds in
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

fractions and provide a group-type analysis for heavy oils. crude oils and related materials and richest in heteroatom
The results from SARA analysis can relate to important species (e.g., sulfur and nitrogen) and organometallic com-
properties of heavy oils such as thermal reactivity, the sta- pounds containing nickel, vanadium, and other metals, the
bility of asphaltenes during processing, tendency to form composition, structure, and properties of asphaltenes differ
coke on catalysts, and the expected yields and composi- depending on the source and separation methods used to
tion of the products from the upgrading processes. These isolate asphaltenes. A particular challenge for molecular
relationships can help select the most beneficial upgrading analysis of asphaltenes is the tendency of self-association, or
process for a heavy-oil stock and the optimum processing aggregation of the constituent molecules and their colloidal
conditions to achieve the desired product yields and properties. Still, much progress has been made recently in
composition. understanding the structure and properties of asphaltenes
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180 Petroleum Refining and Natural Gas Processing

Figure 8.4—HPLC/DAD (top) and HPLC/MS/MS chromatograms of an FCC decant oil sample, indicating the PAHs pyrene (PY),
chrysene (CHRY), and their alkylated analogs, including methyl (M), dimethyl (DM), trimethyl (T), and tetramethyl (Te) substituents
on the PAH ring systems [26].

as reviewed in recent publications [7,9,32,33]. In upgrading select the best feedstock for a given upgrading process, or
heavy oils, the asphaltene fraction clearly poses the most select the best upgrading process for a given feedstock and
challenging issues because it represents the most refractory to select the optimum processing conditions. Some specific
compounds with a high tendency to produce coke, which examples are referenced here on how to use analytical
not only reduces the yields of light distillate products but data for process and feedstock evaluation. Sánchez et al.
also causes operational problems with catalyst deactivation [34] proposed an application of size exclusion chromatog-
and coke deposition on reactor surfaces. Therefore, infor- raphy (SEC) for evaluating the processes for upgrading
mation on the structure and properties of the asphaltene heavy crudes. They compared the elution curves for heavy
fraction of heavy oils is critically important in optimizing crude oil with those of the resulting products from cata-
and controlling the heavy-oil upgrading processes [9]. lytic hydrogenation and developed an algorithm to track
the conversion process. The results were more useful than
8.2.4 Using Analytical Data for Feedstock monitoring the distillation data and the bulk properties
Evaluation and Process Selection such as API gravity and elemental analysis in following
As mentioned at the beginning of this section and discussed the conversion process and pinpointing the problems and
throughout, an ultimate purpose of heavy-oil analysis is to
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
potential improvements in the process.
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Chapter 8 n Heavy-Oil Processing 181

8.3.1.2 Process Description

As an example of deasphalting processes, a supercritical
solvent deasphalting process is described here [38]. There
are processes that do not operate under supercritical pro-
cesses and commonly use propane as the deasphalting
solvent. The process principles are the same in both cases.
The supercritical solvent deasphalting process consists of
the following main stages (Figure 8.6):
1. Introduction of resid feedstock together with the paraf-
finic solvent to the extraction stage.
2. Separation of the DAO and asphalt (pitch) fractions that
are both rich in solvent. This separation occurs in the
extractor, which is specially designed for efficient separa-
tion and minimum contamination of the DAO fraction.
3. Introduction of the DAO fraction with the solvent to the
solvent separator that operates at supercritical condi-
Figure 8.5—Validation TLC/FID analysis of (A) a crude oil
tions to minimize energy consumption.
with analyses of its fractions, (B) asphaltenes, (C) resins, 4. Stripping of the asphalt and DAO with entrained sol-
(D) aromatics, and (E) saturates, separated by column vent in a stripping column.
chromatography [29]. The solvent composition and temperature profile in
the extractor are the two principal variables in the solvent
Zhao et al [35] used supercritical fluid extraction and extraction process.
fractionation (SFEF) with pentane to cut deep into the bot-
toms while readily yielding enough of each fraction to allow 8.3.1.3 Operating Conditions
characterization and reactivity studies on bitumen, heavy- Typical solvents used in the process include n-paraffins,
oil, and conventional crude samples. They concluded that such as propane, n-C4, n-C5, n-C6, and their mixtures. The
the determination of average structures on the basis of bulk solvent is selected based on the feed quality to be processed,
analysis is heavily biased toward the lighter fractions and which affects the yield of the asphaltenes and the softening
provides little information on the properties of the heavier point. Increasing the solvent molecular weight increases
components. A comparison of bitumen pitch with residues the DAO yield and decreases selectivity. If propane is used
from benchmark crudes, heavy oils, and bitumen from non- as the solvent, the selectivity to paraffinic fraction recovery
Athabasca sources showed that the difficult processing of will be very high. With n-butane or n-pentane, the selectiv-
bitumen can be largely due to its much higher asphaltene ity to resins will increase, resulting in higher DAO yields,
and contaminant contents rather than differences in chemi- but the molecular weight and aromatic content of the DAO
cal composition between bitumen and conventional oils. will also increase.
Gonçalves et al. [36] used thermogravimetry (TG) for The solvent-to-residue (S/R) ratio ranges from 3:1 to
the evaluation of heavy petroleum fractions to analyze the 15:1 (typically 8:1). The greater the S/R ratio, the higher the
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

petroleum distillation residues from different Brazilian oils. yield of DAO, but the lower the quality (with lower API, and
Their method was used to predict the formation of carbona- higher viscosity and metals content) along with the higher
ceous residue on the basis of thermal analysis. energy consumption to recover the additional solvent. Fig-
ure 8.7 shows a generic plot of DAO quality and selectivity
8.3 Upgrading Processes as a function of DAO yield.
8.3.1 Deasphalting Technology Pressure at the asphaltene separator ranges between
8.3.1.1 Process Objective 25 and 40 barg, depending on the solvent used. Increasing
The objective of the deasphalting process is to separate the pressure will increase the DAO yield.
heaviest part of an atmospheric or vacuum resid [in which Temperature of the asphaltene separator varies
the asphaltenes and metals (vanadium + nickel) are con- between 50ºC and 230ºC. At higher operating temperature,
centrated] from the lighter part (DAO) using a paraffinic the DAO yield decreases, but DAO quality is improved
solvent. No chemical reactions take place during deasphalt- with lower metal content and lower Conradson carbon
ing. The DAO is almost free of metals, and the asphalt (con- residue (CCR).
taining asphaltenes and resins) can be used as feedstock
for blending to produce pavement asphalts according to 8.3.1.4 Environmental Impact
specifications and for solvent extraction to recover blending The deasphalting process has a relatively low environmen-
components for lubricant production. Solvent deasphalting tal impact. The emissions are only associated with energy
can be integrated with thermal and hydroprocessing for consumption and solvent loss. Typical emissions are 10–15
conversion of DAO in processes such as resid FCC, fixed- or mol % carbon dioxide (CO2) in the flue gas flow (350–400
ebullating-bed hydrocracking to produce lighter hydrocar- Nm3/t load).
bons, and to reduce sulfur [37]. Other uses of asphalt may
include combustion in integrated gasification combined 8.3.1.5 Main Licensors
cycle (IGCC) power plants, coking in delayed coker units, or MW Kellogg has licensed the ROSE process that is used in
contribution to the fuel oil pool of the refinery. If desired, more than 36 units with an installed capacity of more than
resins and asphaltenes can be separated by including addi- 600,000 BPD. The UOP and Foster Wheeler corporations
tional contact stages in the deasphalting process. have licensed more than fifty [40].
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182 Petroleum Refining and Natural Gas Processing

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 8.6—A supercritical solvent deasphalting process flow diagram [38].

8.3.1.6 Opportunities and Threats 8.3.2 Thermal Conversion Technologies

8.3.2.1 Visbreaking Technologies
Opportunities Threats 8.3.2.1.1 Process Objective
The objective of visbreaking is to reduce the viscosity of
This process may be of When processing residues atmospheric or vacuum residua by mild thermal cracking
interest in scenarios in which of heavy or extra-heavy
to produce fuel oil from the heavy ends and to increase the
the asphaltenes can be used crudes, the DAO yield
as fuel to generate energy may be very low if the
distillate yield in a refinery. Depending on the feedstock
in IGCC or can be mixed to target is to maintain properties and thermal severity in the reactor, the process
produce fuel oil. the levels of pollutants will typically achieve 10–25 % of conversion of the heavy
that are carried to the ends to gas, gasoline, and distillates while producing fuel oil
downstream conversion with the desired specifications. Carbon rejection in small
units (nitrogen, sulfur, quantities on the reactor surfaces during thermal cracking
metals, CCR) helps reduce the viscosity of the fuel oil product. The pro-
cess decreases the demand for a cutter stock used as diluent
If there is a well-established The asphaltene stream
market for asphalt and an used as fuel oil component
(e.g., kerosene) that might otherwise be used to reduce the
appropriate feedstock for concentrate contaminants viscosity of the heavy ends to meet the fuel oil specifica-
the process, a good asphalt and, therefore, it will be tions. Adding a diluent may still be needed depending on
product can be produced. more difficult to match fuel the sulfur content of the product and the fuel oil specifica-
specifications. tions. Although, the proper objective of visbreaking is to
reduce viscosity, some refineries may use this mild cracking
This process can be used as process to convert fuel oil into lighter distillates.
a substitute for a vacuum
column because of its lower
energy consumption and
8.3.2.1.2 Process Description
higher DAO yield in cases in There are two types of visbreaking processes: coil or soaker
which asphaltenes have a visbreaking. Figure 8.8 shows a schematic diagram of the
final use. coil visbreaking process. For visbreaking, the feedstock is
introduced into the coil heated in the furnace where the
Integration with thermal cracking reactions take place. At the furnace outlet,
hydroconversion in fixed- or the reaction products are immediately quenched using a
ebullating-bed processes or
portion of the gas oil product from the fractionator to stop
coking processes.
the thermal cracking reactions. The quenched products are
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Chapter 8 n Heavy-Oil Processing 183

Figure 8.7—A generic plot of the concentration of DAO contaminants as a function of DAO yield [39].

Visbreaking severity is limited by the reactivity of the

feedstock and the storage stability of the residual fuel in
accordance with the desired conversion level and desired
reduction in viscosity. Asphaltene content and concarbon of
the feedstocks are important factors to consider for select-
ing an appropriate thermal severity for the process to pre-
vent excessive coking in the coil or soak drum or producing
unstable fuel oil.

8.3.2.1.4 Environmental Impact

Similar to deasphalting, the environmental impact of vis-
breaking is associated with burning fuel in the furnace to
provide energy for thermal cracking, and, to a lesser extent,
burning off the coke deposited in the coil or soaker drum
Figure 8.8—The coil visbreaking process [41]. leading to emissions of CO2, oxides of nitrogen (NOx), and
oxides of sulfur (SOx) in the flue gases.

sent to the fractionator for separation into gas, gasoline, 8.3.2.1.5 Main Licensors
light gas oil, and visbroken resid streams. A steam stripper Main licensors of the visbreaking processes are ABB Lum-
can be used with the fractionator for better separation of the mus, Global, and UOP [40,41].
visbreaking products. In the soaker visbreaking process, a
soak drum is placed after the furnace. Most of the thermal 8.3.2.1.6 Opportunities and Threats
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

cracking reactions in this case take place in the soaker drum.

Opportunities Threats

8.3.2.1.3 Operating Conditions A low-investment and Producing generally low-value

inexpensive process to treat product that may require
Depending on the process objectives and feedstock charac-
the bottom of the barrel to further processing especially
teristics, reaction temperatures range from 450°C to 485°C produce fuel oil with some when dealing with high sulfur
and pressures range from 3 to 10 bar. Higher temperatures flexibility to adjust severity for and metal contents in crude
and lower residence times are used in the coil visbreaking increasing the yield of lighter oils.
process. Residence times can vary from 1 min (associated distillate products (e.g.,
with high temperatures in coil visbreaking) to 10 min (for gasoline and light gas oil).
lower temperatures used in soaker visbreaking).
Ability to treat a wide range Loss of carbon depositing on
A relationship between the thermal severity of vis- of residua by selecting the reactors as a byproduct of
breaking (kt) and conversion (x) can be defined in terms of the appropriate process thermal cracking, limiting the
the reaction temperature (T) and time (t) assuming a first- configuration, coil, or soaker processability of crudes with
order kinetic expression with a rate constant k as follows: visbreaking with careful high asphaltene content or
consideration of the product high CCR.
fuel oil stability.
kt = –ln(1 – x) (8.1)

Using an Arrhenius relationship for the rate constant 8.3.2.2 Coking Technologies and Process
k = A exp(–Ea/RT) and a good estimate of the apparent acti- Objective
vation energy (Ea), one can calculate alternative temperature Coking is the most severe thermal process used in the refin-
and time combinations needed for a given conversion level. ery to treat the very bottom-of-the-barrel vacuum residua.
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184 Petroleum Refining and Natural Gas Processing

Because of the high severity of thermal cracking, the resi- approximately 485°C at a pressure of 2.5 barg. Steam is
due feed is completely converted to gas, light and medium added to prevent coking in the heater and the heated feed
distillates, and coke with no production of residual oil. is introduced from the bottom of one of the coke drums
Two different coking processes are used in the refineries: (drum A). The coking takes place in the insulated coke

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
delayed coking and fluid coking. The common objective of drum as the drum fills up for a period of 16–18 h. While
both coking processes is to maximize the yield of distillate drum A is being filled up, drum B is decoked by using
products in a refinery by rejecting large quantities of car- hydraulic cutters and the coke is removed from the bottom
bon in the resid as solid coke, known as petroleum coke. of the drum. As the coking in drum A is completed, drum
Complete rejection of metals with the coke product pro- B should be decoked, sealed, heated, and prepared for
vides an attractive alternative for upgrading the extra-heavy switching the feed. The coking cycle is controlled such that
crude and bitumen and that is particularly useful for initial the vacuum residue is continuously fed to the unit (because
processing of tar (or oil) sands for liberating the hydro- the vacuum column works around the clock) and the fluid
carbons from the sand that is left behind with the coke. products are recovered continuously while coke is removed
Finding markets for the coke product as fuel or as filler intermittently in a semicontinuous process scheme. There-
for manufacturing anodes for the electrolysis of alumina fore, there are at least two coke drums in every delayed
(possible only with petroleum coke from delayed coking) coking unit, and some units have more than two drums. All
makes the economics of coking more attractive by creating of the heat necessary for coking is provided in the heater,
value for the rejected carbon. Sulfur and metal contents of whereas coking takes place in the coke drum; hence, the
the petroleum coke as determined by the sulfur and metal process is called “delayed coking.”
contents of the resid feed are two important factors that The hot product vapors and steam from the top of the
affect the commercial value of petroleum coke. Of the two drum are quenched by the incoming feed in the fractionator
coking processes, delayed coking is the preferred approach to prevent coking in the fractionator and to strip the lighter
in many refineries that process heavy crudes. components of the vacuum residue feed. The fractionator
separates the coking products into gases, coker naphtha,
8.3.2.3 Delayed Coking: Process Description coker light gas oil, and coker heavy gas oil. A sidesteam
and Operating Conditions stripper is used with the fractionator to ensure a good sepa-
The delayed coking process has a prominent place in a refin- ration between the coker naphtha and light gas oil streams.
ery that processes heavy crudes [42,43]. Delayed coking of The delayed coking operating variables include heater
vacuum distillation residue or FCC decant generates liquid outlet temperature, pressure, recycle ratio, and cycle time.
products as feeds for further processing in various units to These variables are selected based on feed properties such
contribute to the blending pools for all of the distillate liquids, as the characterization factor, asphaltene content, and CCR
including gasoline, jet fuel, and diesel fuel. Further process- to ensure that coking in tubular heaters is minimized and
ing of the delayed coking products, such as hydrotreatment, liquid product yield is maximized. The recycle ratio, which
is necessary particularly with the resid feeds that have high is typically 3–5 %, is used to control the endpoint of the
sulfur and nitrogen contents to reduce these heteroatom spe- coker heavy gas oil. The coke yield can vary from 20 % to
cies according to the specifications of the final products. 30 % depending on the feed properties and coking condi-
Figure 8.9 shows a schematic flow diagram of the tions. Gary and Handwerk [44] proposed equations to pre-
delayed coking process. The resid feed is introduced to the dict coke and other product yields on the basis of the CCR
fractionator after being heated in the heat exchangers with of the vacuum residue and gave estimates of the distribution
the coker gas oil products. The bottoms from the fraction- of sulfur in the feed among the coking products, suggesting
ator, including the heavy ends of the vacuum residue feed that up to 30 wt % of the sulfur in the feed ends up in the
with heavy coker gas oil recycle, are mixed with steam and coke, 30 wt % in the gas product, and 20 wt % in the coker
sent to the tubular heater in the furnace to be heated to heavy gas oil.

Figure 8.9—A schematic flow diagram of the delayed coking process (Modified from [44]).
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Chapter 8 n Heavy-Oil Processing 185

8.3.2.3.1 Structure, Properties, and Uses of Coke 8.3.2.4 Fluid Coking and Flexicoking
Delayed coking of vacuum residua produces two types Process Description, Operating Conditions,
of coke that are called “sponge coke” and “shot coke” and Products
because of their appearance. Shot coke consists of the Fluid coking and flexicoking are fluid-bed processes devel-
agglomerates (10–20 cm in diameter) of discrete hard oped from the basic principles of FCC with close integra-
spherules that may range in diameter typically from 0.2 tion of endothermic (cracking, coking, or gasification) and
to 0.5 cm and resemble bee-bee shots. Vacuum residua exothermic (coke burning) reactions. In fluid coking and
with reactive asphaltene fractions tend to produce shot flexicoking processes, part of the coke product is burned to
coke during delayed coking because of fast development provide the heat necessary for coking reactions to convert
and hardening of a liquid crystalline phase (carbonaceous vacuum residua into gases, distillate liquids, and coke. Flex-
mesophase) during coking [45]. Sponge coke is formed by icoking, as a variation of fluid coking, provides the options
a more slow and extended development of carbonaceous of partial or complete gasification of the coke product to
mesophase. The differences in the extent of carbonaceous produce a fuel gas with some or no coke in the product
mesophase development between sponge and shot coke slate. Different from the bulk liquid-phase coking in delayed
can be identified by examining their microstructure using coking, coking takes place on the surface of circulating coke
polarized-light microscopy. Shot coke is used mainly as particles of coke heated by burning the surface layers of
fuel and in some niche applications such as the production accumulated coke in a separate burner. Figure 8.10 shows
of titanium dioxide (TiO2). Sponge coke can also be used as a schematic flow diagram of the fluid coking process [46].
fuel or for production of carbon anodes used for extraction The preheated vacuum residue is sprayed onto the hot
of aluminum from alumina by electrolysis if their sulfur coke particles heated in the burner by partial combustion
and metal contents are sufficiently low as identified by the of coke produced in the previous cycle. Using fluid beds in
specifications [43,45]. Using FCC decant oil in delayed cok- the reactor and burner provides efficient heat transfer and
ing under different conditions than those used for coking fast coking on a collectively large surface area of the small
vacuum residua produces a more “crystalline” coke called coke particles circulating between the reactor and burner.
“needle coke” that is used to manufacture graphite elec- The products of coking are sent to a fractionator (similar
trodes for use in electric-arc furnaces for recycling scrap to that used in delayed coking after recovery of fine coke
iron and steel. The delayed coking process thus provides particles). Steam is also added at the bottom of the reactor
an interface between the petroleum refining and metal (not shown in the figure) in a scrubber to strip heavy liquids
manufacturing industries. sticking to the surface of coke particles before they are sent
to the burner. This steam also provides fluidization of coke
8.3.2.3.2 Environmental Impact of Delayed Coking particles in the reactor. The reactor and the burner operate
The environmental impact of delayed coking includes air at temperatures of 510–570°C and 595–675°C, respectively.
emissions from burning fuel for heating the feed and water Higher temperatures and short residence times in the
pollution from the fractionator and decoking operations reactor lead to higher liquid and lower coke yields compared
that generate wastewater that needs to be treated. with those of delayed coking. Coke is deposited layer by layer
on the fluidized coke particles in the reactor. Air is injected
8.3.2.3.3 Main Licensors of Delayed Coking into the burner to burn 15–30 % of the coke produced in the
Main licensors of the delayed coking process include Foster reactor, part of the particles are returned to the reactor, and
Wheeler, ABB Lummus, UOP, and ConocoPhillips. the remainder are drawn out as the fluid coke product. The
flue gas from the burner is sent to a carbon monoxide (CO)
8.3.2.3.4 Opportunities and Threats of Delayed Coking boiler to raise additional heat for the refinery [41,43]. Ham-
mond [47] reported data on the product yields from fluid
Opportunities Threats coking and uses of fluid coke that include combustion for
Ability to process any kind Loss of carbon and hydrogen
power generation and fuel for the cement industry.
of feed including extra- in the relatively low-value Figure 8.11 shows a schematic diagram of flexicok-
heavy crudes and bitumen to solid byproducts (coke and ing. A fluid bed is added for partial combustion and
produce distillate products gas) and low yields of liquid gasification of coke produced in the reactor with air and
with complete rejection of products that need further steam to produce a synthesis gas. The hot coke particles
metals and large portions of processing in accordance with from the gasifier are sent to the heater to heat the cold
the heteroatoms sulfur and fuel specifications. coke particles removed from the reactor that are circu-
nitrogen. lated back to the reactor to provide the heat necessary
Shortening cycle times and Material problems with for coking. After removing the fine particles from the gas
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

increasing liquid yields processing more corrosive and particles by cyclones, the gas is cooled in a direct-contact
and throughput with the sour feedstocks increasing cooler to condense the sour water and recover the flexi-
optimization of operating the cost of processing in gas. Maples et al. [48] reported correlations between the
conditions and process this relatively inexpensive CCR of the vacuum residue and the product yields and
innovations. upgrading option. gas composition.
Finding markets for the Increasing heteroatom and The environmental impact of fluid and flexicok-
byproduct cokes improves the metal contents, particularly ing include air emissions in the flue gases from the CO
economics of delayed coking. with the heavy crudes, boiler in fluid coking and the production of sour water
limits the use of byproduct in flexicoking. The licensors of fluid coking and flexicok-
cokes, which may need to be ing include ExxonMobil, ConocoPhillips, and Haliburton
landfilled at additional cost. KBR [37].
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186 Petroleum Refining and Natural Gas Processing

Figure 8.10—A schematic flow diagram of the fluid coking process [46].
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 8.11—A schematic diagram of the flexicoking process [46].

8.3.2.4.1 Opportunities and Threats for Fluid Coking 8.4 Catalytic Hydrotreating and
and Flexicoking Processes Hydrogen Addition Technologies
8.4.1 Catalytic Fixed-Bed Processes
Opportunities Threats 8.4.1.1 Objective
The objective of catalytic hydrotreating [including hydrode-
Using the low-value coke Although the liquid yields sulfurization (HDS), hydrodenitrogenation (HDN), hydro
byproduct as an energy are higher than those
demetallation (HDM), and aromatics hydrogenation] and
source without needing any obtained by delayed
other fuel could provide a coking, the quality of the
catalytic hydrocracking of residua (atmospheric, vacuum
significant opportunity with liquid products is inferior residue, and residues from other conversion processes) and
high-energy prices. compared with delayed crude oils is to produce higher-quality residua and small
products. amounts of lighter products (naphtha, diesel, VGO) with
lower contaminants in the treated residue such as sulfur,
Easy integration with power Increasing the metal and nitrogen, and metals (vanadium + nickel). In many cases,
generation because of small sulfur contents in the the residue hydrotreating units are pretreatment processes
coke particle size (fluid residua, and thus in fluid or
to other downstream conversion units such are resid-FCC,
coking) or gas production flexicoke, would make flue
(flexicoking). gas treatment more costly.
delayed coking, and ebullating-bed hydroconversion pro-
cesses, among others [37].
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Chapter 8 n Heavy-Oil Processing 187

Table 8.2—Typical Characteristics of Venezuelan and Canadian crudes and their vacuum residua
Cold Lake Lloydminator Athabasea Hamaca

Whole Rosld Whole Rosld Whole Rosld Whole Rosld

Production properties Crude Crude Crude Crude

TRP cut point °F C5+ 1049+ C5+ 1049+ C5+ 1049+ C5+ 1049+

TRP cut point °C C5+ 585+ C5+ 585+ C5+ 585 C5+ 585+

Yield vol % 100 43.1 100 41.5 100 44 100

Yield wt % 100 46.5 100 44.5 100 47.1 100 59.5

Gravity API 11 0.5 15 5.1 7.9 -1.2 7.9 -0.07

Specific gravity 0.993 1.072 0.958 1.038 1.015 1.096 1.016 1

Sulfur wt % 4.6 6.5 3.6 5.5 4.9 6.7 4.1 4.8

Nitrogen wt % 0.37 0.69 0.23 0.37 0.4 0.7 0.8

CCR wt % 12.9 27.3 10 22.1 13.4 27.7 14.5 24.2

Vanadium ppmw 182 390 120 270 222 471 466 783

Nickel ppmw 65 140 50 113 87 184 96 161

8.4.1.2 Typical Feedstocks conditions, and the nature of the catalysts need to be
Table 8.2 shows the typical characteristics of heavy-crude oil adequately designed.
and vacuum residua from Canadian and Venezuelan heavy The deposition on the catalyst of the impurities of the
crudes. Generally, as shown in the table, the heavy crudes feed such as vanadium, nickel, and iron or carbon residue
have a high sulfur content that is distributed among the dif- reduces the catalytic activity and plugs the reactor bed.
ferent fractions. Typical sulfur compounds are mercaptans, When that happens, the catalyst must be replaced. This
thiophene, benzotiophenes, and dibenzothiophene, particu- phenomenon has led to innovative reactor designs that per-
larly its alkyl-substituted analogs, which require severe cat- mit continuous replacement of the poisoned catalyst with
alytic hydrotreating because of their low reactivity. Another the new catalyst.
important parameter that affects the hydrotreating of heavy Figure 8.12 shows the main criteria to follow for select-
residua is the metal (such as vanadium and nickel) content. ing the type of technology for HDS and/or hydrocracking
These metals tend to deposit on catalysts during catalytic of residues. Typically, the parameters to take into account
hydrotreating and reduce the activity of the catalysts. It are the metal content and the level of conversion required.
can be expected that when the amount of heavy crude The content of asphaltenes and their thermal stability
increases in the refinery crude base, the hydrogen demand during the preheating stage of the process is another fac-
for hydrotreating processes will increase and the expected tor that needs to be taken into account. They may show a
life of the catalyst will decrease because of the deactivation tendency to produce a small fraction of unstable asphaltenes
of catalyst by the deposition of metals on the active sites that may be deposited on top of the reactor, which forms coke
of catalysts. Therefore, the operating costs to process such and causes poisoning and early plugging of the catalytic bed.
heavy crudes will increase. Sometimes, depending on the Another important factor for fixed-bed reactors is the
type of feedstock, revamps of hydrotreating units will be amount of ash in the feed (mainly FeS) causing pressure
required to maintain an economical operation with a larger drop due to bed plugging. This is especially important when
on-stream factor between the catalyst replacements. processing acidic crudes because they might corrode the
Table 8.3 shows a comparison of the vacuum residua of metal units upstream of the hydrotreating unit and such
light crudes and heavy crudes. The vacuum bottoms of Ara- corrosion products are concentrated in the bottoms of
bian light and heavy crudes have a high sulfur but low metal the crude (vacuum or atmospheric residue) that are fed to
content when compared with a typical residue of a heavy crude the hydrotreating fixed-bed reactor. Typically, commercial
like Maya that also has a high sulfur, but also a higher metal, operation of this type of unit allows a maximum content of
CCR (concarbon), and asphaltene contents. Asphaltenes and metals of approximately 200–250 ppm (vanadium + nickel).
CCR are also important feed parameters for hydrotreating The current worldwide residue fixed-bed hydropro-
because they increase the tendency to deposit coke on the cessing capacity is approximately 2.4 million bbl/day in 60
catalyst bed (especially at the top), reducing the activity of the installations.
catalyst and increasing the reactor pressure drop. At present, the commercial processes for hydrotreating
and hydrocracking the residua are based on conventional
8.4.1.3 Main Characteristics of Fixed-Bed fixed-bed reactors and fixed-bed reactors with moving-bed
Processes guard reactors.
There are different configurations and reactors used in the
fixed-bed hydrotreating processes. Depending on the qual- 8.4.1.4 Conventional Fixed-Bed Reactors
ity of the feedstock and the required yields and quality of This type of unit needs to be shut down periodically to
the products, the configuration of the unit, the operating replace the demetallation catalyst (HDM) of the guard
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188 Petroleum Refining and Natural Gas Processing

Table 8.3—Typical Characteristics of light crudes vacuum residua compared with the Maya
heavy crude vacuum residua
Arabian Light Arabian Heavy Ural Odessa Maya

Vacuum Resid Properties Unit 538+ °C 538+ °C 538+ °C 538+ °C

Yield v% 16.71 25.09 21.33 32.82

Yield wt % 20.14 30.86 25.12 38.31

Density at 15°C g/ml 1.0323 1.0448 1.0180 1.0730

Specific gravity at 15,6/15,6 °C g/ml 1.0330 1.0455 1.0187 1.0738

API °API 5.48 3.93 7.40 0.28

Sulfur wt % 4.160 5.350 2.610 5.230

Kinematic Viscosity

Viscosity @ 135°C cSt 5859 1059 9143

Viscosity @ 150°C cSt 597.1 178.0 3727

Viscosity Brookfield

Viscosity Brookfield @ 135°C cP 5.825 1059 9,100

Viscosity Brookfield @ 150°C cP 581 178.0 3,673

TAN mg KOH/g 0.10 0.20 0.85 1.15

Nitrogen ppm 409 3693 5287

Nickel ppm 25.8 47.0 76.0 111.0

Vanadium ppm 91.6 171.0 226.0 564.0

Sodium ppm 1.3 <5 1.0 28.0

Concarbon wt % 21.13 23.32 16.69 29.52

Asphaltenes wt % 11.20 11.65 6.36 26.30

Hydrogenation units that use fixed-bed reactors use

between one and six reactors in series and can operate in
ďƵůůĂƚŝŶŐ ĞĚ two modes—HDS and HDS + hydroconversion (HDC)—by
increasing the reaction temperature, increasing the residence
time, and using a different type of catalyst. When the catalyst
is deactivated by coke and metal deposition and the opera-
tional limitations (such as high-pressure drop and maximum
&ŝǆĞĚ ĞĚ reactor temperature) are reached, the units are shut down to
replace the catalyst.
Figure 8.13 shows a typical process layout of a residue
hydrotreating fixed-bed unit. It consists of one guard reac-
Figure 8.12—Range of metals and residue conversion for fixed- tor with a HDM catalyst and one or more HDS reactors.
bed reactors processing [49]. The main limitation of this type of process (Table 8.4) when
processing feeds with high metal content is the deactivation
of the catalyst bed and the potential differential pressure
reactor or the HDM catalyst of the main reactor if a guard increase in the guard reactor, which indicates the plugging
reactor is not installed. of the catalytic bed by metals, solid carryover with the feed,
The main process licensors are Chevron, UOP/Unocal, and coke deposition. All of these phenomena reduce the
Exxon, Shell, and IFP. duration of the operating cycle.
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Chapter 8 n Heavy-Oil Processing 189

the operation without shutting down the unit. Normally, the

guard reactors operate in series. When the HDM catalyst in
the first guard reactor becomes deactivated or experiences a
high pressure drop, the reactor is taken out of operation. The
unit continues in normal operation using the second guard
reactor. After the catalyst in the plugged reactor is replaced,
the reactor is put back into operation, but in the second posi-
tion. This configuration allows for longer operating cycles
while processing feed with high metal and asphaltene con-
tents. Typical feeds for this type of process are atmospheric
or vacuum residua of light/heavy Arabian crudes.

8.4.2 Fixed-Bed Hydrotreating Reactors with

Moving-Bed Guard HDM Reactors
Figure 8.13—Typical fixed-bed residue hydrotreating
configuration using guard reactor [50].
Another alternative to hydroprocess residues with fixed-bed
reactors is to use guard reactors with moving beds. In this
case, the catalyst is circulated by gravity through the inte-
rior of the reactor, with periodic addition of fresh catalyst
Table 8.4—Factors Affecting the Conventional
at the top of the reactor and a purge of the used catalyst at
Fixed-Bed Hydrotreating Reactors and the
the bottom. The main advantage of this technology and the
Duration of the Operating Cycle
permutable fixed-bed technology is that they enable pro-
Factors Impact cessing of feeds with high metal content while maintaining
Solids deposition carried Unit processing capacity longer operating cycles.
with the feed and increase in decreases because of unit The main commercial processes include OCR from
pressure drop shutdown Chevron, which uses an upflow (feed and H2) catalytic
guard bed in a minimum fluidization state of the catalyst.
Coke deposition due to Catalyst deactivation, bed
The catalyst is added and removed on a regular basis in a
asphaltene decomposition plugging, reduced cycle
batch operation to maintain the catalytic activity. The OCR
length
reactor precedes the conventional down-flow fixed-bed
Metal deposition Deactivation of HDM and HDS reactors. This technology can also be applied without cata-
catalyst lyst replacement to avoid the bed plugging in existing fixed-
bed units, allowing for hydrotreating of heavier feeds [52].
Another commercial process is HYCON from Shell,
which uses a bunker flow guard reactor. In this case the
catalyst flows down for removing the spent catalyst at the
bottom of the reactor and replaces it with fresh catalyst at
the top of the reactor while maintaining the normal opera-
tion of the unit. Here the feed and the H2 flow down as in a
conventional fixed-bed reactor configuration. The catalyst
is also added periodically to maintain its catalytic activity
(Figure 8.15). The catalyst is replaced at a rate to ensure a
total plant running time of at least 1 year [53,54].

8.4.2.1 Catalysts Used in Fixed-Bed Reactors

The catalysts using fixed-bed reactors for hydrotreating
residua consist typically of Mo, nickel, Co, and W oxides,
among others, that are dispersed on an alumina, silica, or
silica/alumina base. Zeolites could also be used depending
Figure 8.14—Typical fixed-bed residue hydrotreating
on the target in conversion and the quality of the feed used.
configuration using a permutable guard reactor [51].
The catalysts are active sulfided forms. Therefore the metal
oxides from the fresh catalyst need to be sulfided before
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

To avoid the shutdown of the unit because of high pres- the catalyst is put in contact with the residue. Typically,
sure drop or deactivation of the HDM catalyst of the guard dimethyl disulfide (DMDS) is used to sulfide the catalyst at
reactor, low-cost bypass distributors may be placed at the specific conditions indicated by the catalyst manufacturer.
top of the reactors to bypass the catalytic bed when high To process feeds with high metal and asphaltene con-
pressure drop is reached, thereby allowing longer operat- tents, catalysts with large pore diameter and pore volume
ing cycles. This solution tends to stretch a little further the are required to store the maximum amount of metals and
cycle of operation and therefore the processing capacity of coke from the residue and maintain, as long as possible, the
the unit without shutdown. HDM activity of the catalyst in the guard reactor.
Other alternatives include using a permutable guard Because most of the metals are removed from the resi-
reactor system such as in the Axens Hyvahl swing reac- due in the HDM stage, the HDS catalyst should have a smaller
tor process, shown in Figure 8.14, which allows for the pore diameter and a large surface area (200–300 m2/g) to
replacement of the deactivated or plugged guard reactor in maximize the HDS activity. Typically, molybdenum sulfide
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190 Petroleum Refining and Natural Gas Processing

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 8.15—Shell HYCON bunker flow HDM guard reactor [53,54].

(MoS2) promoted with cobalt sulfide (CoS) usually sup-

Table 8.5—Relative Activity of Different ported on alumina is widely used in HDS processes. The
Hydroprocessing Catalysts nickel sulfide (NiS)/MoS2 catalyst is used when HDN and
Catalyst Aromatic aromatic saturation is also desired. Tungsten sulfide (WS)
Composition HDS HDN Saturation is used to promote the aromatic saturation activity. Table
8.5 shows a qualitative comparison of the activity of the
MoS2 /CoS Excellent Good Fair
different HDS catalysts used in fixed-bed reactors.
MoS2 /NiS Very good Very good Good

NiS/WS Good Good Excellent 8.4.2.2 Operating Conditions for Fixed-Bed

Reactors
Table 8.6 shows typical ranges of the operating condi-
tions of conventional fixed-bed, permutable fixed-bed,
Table 8.6—Typical Operating Conditions and moving-bed processes. As main characteristics, high
for Fixed-Bed and Moving-Bed Reactors for operating pressures and low space velocities can be noted.
Residue Hydrotreating Processes Operating conditions are defined mainly by the type of
Conventional Permutable Moving feedstock that a refinery needs to process and the level of
Fixed Bed Fixed Bed Bed HDS and conversion required.

Pressure (Bar) 70–100 70–150 100–200 8.4.2.3 Environmental Impact

Temperature (ºC) 360–420 360–420 360–420 Table 8.7 shows a summary of the environmental impacts
of the residue hydrotreating processes.
LHSV (h ) -1
0.1–0.5 0.1–0.5 0.1–0.5

Nickel + Va in <100 <200–300 <200–300 8.4.2.4 Opportunities and Threats

feed (ppm)

Conversion, wt % Very low Low Low Opportunities Threats

Residue stability Good Good Good Commercial technologies Limited commercial

widely used to reduce sulfur application to heavy crudes
of atmospheric and vacuum with high metal and high
residues to be fed to other asphaltene contents,
Table 8.7—Environmental Impact of Residue conversion processes such typically limited to lower
Hydrotreating Processes as resid FCC or to prepare than 200 ppm.
Atmosphere CO2 emissions coming from preheating furnace components to produce low-
emissions and from the hydrogen production unit. sulfur fuel oil.
H2S produced is recovered as elemental sulfur Integration with deasphalting Limited conversion capacity
product process in which the DAO with compared with ebullating
C1–C4 is consumed as fuel gas in the refinery. low asphaltenes and metal is bed or delayed coking
Liquid Not significant. processed in resid hydrotreating/ processes. Susceptible to
effluents hydrocracking reactors. Feeding premature cycles because
the asphaltenes to coking of sudden pressure drop
Solid Spent catalyst with the metals removed from units or gasification units may increases.
residues the residue (vanadium, nickel) that is normally be an interesting alternative
processed for metal recovery. to improve liquid yields in
HDT of residues generate more spent catalysts refineries while increasing
than other HDT units existing in the refineries. heavy-oil processing.
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Chapter 8 n Heavy-Oil Processing 191

Opportunities Threats
needs to be diluted or upgraded so that it can be trans-
ported in oil pipelines. Typical viscosity specifications for
Development of new High CAPEX compared transportation in oil pipelines are on the order of 300 cSt
hydrotreating with higher metal with other conversion at 30ºC. To reach such a viscosity, the heavy crude needs to
retention capacity catalysts to technologies because of be diluted between 20 % and 50 % depending on the type
improve the economics of this high residence time and
of diluent used. Diluents used could range from naphtha
technology. Deeper knowledge operating pressure.
of the chemistry of asphaltenes
to diesel or other light-crude oils or condensates. This
and metal deposition on the operation typically needs a low capital expenditure, but
catalyst will be required. the diluent consumption may be an issue if it is not pos-
New developments in HDM sible to maintain the diluent in a closed cycle. On the other
catalyst support to improve hand, heavy crudes could be partially upgraded to produce
metal retention capacity and a synbit (heavy crude or bitumen diluted with synthetic
minimize coke deposition in distillates) or totally upgraded to produce a light SCO. In
guard reactors. either case, an imported diluent is not needed. In the case
Nanotechnologies may of partial upgrading, the quality of the synbit should be
contribute in such new
compatible for transportation in an oil pipeline; that is,
developments.
with an API gravity between 16°API and 25°API. In the
Bunker fuel is a growing market New slurry hydroconversion case of SCO production, transportation in a pipeline is a
and will be regulated to lower technologies, now in less significant issue than the quality of SCO required in
sulfur and metal specifications. demonstration stage or the market or the integration with the refinery where it
large pilot units, integrating is going to be processed. The API gravity of SCO typically
a slurry reactor of the
ranges between 25°API and 32°API. Integrated commercial
residue with a fixed bed of
the distillates in the same
upgrading schemes of heavy crude are in operation mainly
unit. This could be a new in Canada and Venezuela.
refining process to produce Figure 8.17 shows the process scheme used by SUN-
higher-distillate yields with COR located in Canada. SUNCOR, with a base capacity
products almost free of of 267 Mbbl/day, has an upgrading scheme that includes
sulfur and nitrogen while delayed coking followed by independent hydrotreating of
processing residues with the naphtha, diesel, and VGO distillates to produce low-
high metals and asphaltenes. sulfur SCO. The present SUNCOR configuration has the
flexibility to produce various sweet and sour products and
8.5 Integrated Processes: Commercial diluted bitumen.
Process Schemes for Heavy-Oil Upgrading The Syncrude upgrader is also in operation in Canada
Considering the typical characteristics of the heavy crudes, (Figure 8.18) with a capacity of 350 Mbbl/day and includes
several strategies are used to transport them to the market in its process scheme light-crude fining and fluid coking
(Figure 8.16). Because of its high viscosity, heavy crude processes. The light-crude fining unconverted vacuum

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- Figure 8.16—Typical options to transport and upgrade heavy crudes.

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192 Petroleum Refining and Natural Gas Processing

Figure 8.17—SUNCOR process flow diagram [55].

Figure 8.18—Syncrude process flow diagram [56].

ottoms are processed in the fluid coker, producing more

b and metals in the feed also reduce the catalyst consump-
distillates and coke. The products from the conversion units tion. The upgrader also includes an integrated hydrotreat-
are hydrotreated in conventional fixed-bed hydrotreating ing reactor to reduce the sulfur and nitrogen content in the
units to produce a high-quality SCO called “SSB” (Syn- distillates produced. The HUSKY BiProvincial upgrader in
crude synthetic blend) of 31°API and approximately 0.1 % Canada with a capacity of 65 Mbbl/day uses a H-OIL pro-
sulfur without the vacuum bottoms. The Scotford Upgrader, cess as a primary upgrading unit. The unconverted residue
which is a part of the joint venture project between Shell from the H-OIL unit is sent to the delayed coker unit. In this
Canada, Chevron Canada, and Marathon Oil Sands L.P., is case, the amount of produced coke is reduced significantly,
operated by Shell Canada and has a capacity of 155 Mbbl/ increasing the liquid yield of the upgrader. The H-OIL and
day. Light-crude fining hydrocracking ebullating bed is the delayed coking products are hydrotreated together, produc-
primary upgrading technology used in this approach. ing 59 Mbbl/day of high-quality SCO.
The partial removal of the asphaltenes and very fine Figure 8.19 shows the OPTI process scheme of the
sand in the production facility improved its operation Long Lake project in Canada located in an area of cold
stability at higher conversion levels. The lower concarbon production in Athabasca that requires the use of steam
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Chapter 8 n Heavy-Oil Processing 193

Figure 8.19—Long Lake project upgrader configuration with OPTI technology [55].

Table 8.8—Upgraders in the Orinoco Oil Belt in Venezuela. Capacity, SCO and Coke Yield
(Source Reference [57])
Heavy Oil Production, Synthetic Crude Oil Synthetic Crude Coke Production
Upgrader Upgrading Process Mbbl/d Production, Mbbl/d Oil, °API Mt/d
Petrozuata Delayed Coking 120 104 14–22 3,000

SINCOR Delayed Coking, 180 156 27–32 5,000

and Hydrocracking

Cerro Negro Delayed Coking 120 108 14–22 2,000

Hamaca Delayed Coking, 200 180 27–32 5,000

and Hydrocracking

for the heavy crude production with steam-assisted grav- the production field represents approximately 21 % of the
ity drainage (SAGD) technology. The capacity of the first total heavy oil produced.
stage will be 70 Mbbl/day and it is going to be expanded In the case of heavy Venezuelans crudes in the Orinoco
up to 140 Mbbl/day of heavy crude in the future. The OPTI Oil Belt, the only considered technology is delayed coking. As
process is a new technology. This project is at this moment shown in Table 8.8, two classes of synthetic crude are pro-
in the first stage of construction. The process scheme duced. One is of low quality (14–22°API) in the associations of
integrates solvent deasphalting with thermal cracking and PETROZUATA and Cerro Negro, where only the coker naph-
VGO hydrocracking. The vacuum resid from the crude is tha is stabilized by very mild hydrotreating (saturation of
sent to a solvent deasphalting unit where the DAO is sepa- diolefines via hydrogenation) to avoid fouling and solids pre-
rated from the asphaltenes. The DAO is sent to the thermal cipitation by the diolefin polymerization. The coker distillates
cracking unit. The product from the thermal cracker unit is are mixed with virgin heavy crude to produce a Synbit of the
recycled back to distillation where unconverted residue is required quality. The other synthetic crude is produced in the
fed again to the process together with the virgin residue. All associations of SINCOR and Hamaca that are of high quality
of the distillates are sent to a hydrocracker to produce 59 (27–32 °API). In this case, the virgin and coker atmospheric
Mbbl/day of synthetic crude of approximately 40° API grav- gas oils (AGO) are hydrotreated together and the virgin +
ity and almost no sulfur. The asphaltenes coming from the coker vacuum gas oils (VGO) are sent to a mild hydrocrack-
solvent deasphalting are sent to a gasification unit where ing unit to increase the distillate yields and quality of the
the hydrogen required by the upgrader is produced as well SCO. Considering the four upgraders together represents a
as the energy to generate the steam required by the SAGD total heavy-oil production of 620 Mbbl/day with a syncrude
technology in the production field. The energy required by
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production of 550 Mbbl/day and 15,000 t/day of coke.
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194 Petroleum Refining and Natural Gas Processing

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Advances in Petroleum Refining Processes
Isao Mochida1, Ray Fletcher2, Shigeto Hatanaka3, Hiroshi Toshima4, Jun Inomata5, Makato Inomata6,
Shinichi Inoue7, Kazuo Matsuda7, Shigeki Nagamatsu6, and Shinichi Shimizu7

9.1 Introduction unit resulted in a wave of new unit construction. Innova-

This chapter describes some recent advances in selected tion during this period was unparalleled. By 1950, over 500
processes used in petroleum refineries. The advancements patents had been issued related to FCC technology alone.
include process innovations and modeling for increasing the One key element in the development of FCC was an
flexibility of refining processes to treat the feedstocks and exceptional collaboration between multiple companies for
intermediate products for handling increasingly heavy and the development of this new process. In 1938, the Standard
high-heteroatom-content feeds to produce fuels according Oil of New Jersey (now Exxon Mobil) formed a consortium
to increasingly strict environmental regulations on the fuel of eight companies including M.W. Kellogg Co., Royal Dutch
products and refinery operations. Some recent publications Shell, the Standard Oil Co. of Indiana, Anglo-Iranian Oil
have reviewed the advancements in the field and provide Co. (today’s BP), Universal Oil Products Co. (today’s UOP),
good references to the processes that are not covered here the Texas Corp. (which would become Texaco), and IG
because of space limitation [1–4]. The developments and Farben (which was eventually dropped in 1940). This group
advancements in catalyst design and use in refining processes of eight companies became known as the Catalytic Research
are discussed in Chapter 10 following a similar outline used Associates (CRA). In addition, American wartime legisla-
in this chapter. tion required sharing of FCC patents for the duration of the
war plus 7 years. The CRA group plus government action
9.2 Advances in Fluid Catalytic Cracking catapulted the swift development of the fluidized catalytic
(FCC) and Hydrotreatment of Cracker cracker.
Naphtha Several key discoveries were made by the CRA associates,
9.2.1 The Birth and Evolution of FCC and which were critical in overcoming the many engineering
Innovation in Unit Design obstacles in design of the first few FCC units. These include:
The FCC unit possesses perhaps the most unique history the concept of the standpipe [7] (for transferring solids from
of all the chemical processes in existence today. By 1910, regions of lower pressure into regions of higher pressure),
there were an estimated 500,000 cars on the roads of North the dense bubbling bed [7,8] (which far exceeded the Stokes’
America [5]. This resulted in the first gasoline shortages in law settling velocity of particles), and liquid feed injection
history. This demand served as a driving force for innova- (alleviating fears of “mud” formation in the injection zone).
tion [6]. Many new refining processes evolved from this The FCC unit rapidly matured into the process that we
need including multiple thermal processes such as the recognize today as the FCC unit. The first operating unit,
Dobbs unit (the origin of UOP), the Houdry unit (the fore- PCLA No. 1, was designed as an “up flow” unit possessing no
father of the FCC), and eventually the fluidized catalytic bubbling beds. Even prior to PCLA No. 1 start up, the next
cracker. Additionally, with the advent of aviation warfare two units were being designed as “bed crackers” possessing
in World War II, there was a critical shortage of aviation bubbling beds in both the reactor and regenerator vessels.
jet fuel. This jet fuel was produced primarily via sulfuric A significant milestone in the development of the FCC
alkylation units which produced a demand for butylenes. process was the result of incorporation of zeolites into the
The steady development of refining processes to supply alumina-based synthetic catalysts used at the time (Plank
the gasoline shortages of the early 1900s in conjunction and Rosinski, Mobil Oil, 1962). The inclusion of zeolite into
with the war effort culminated in the startup of the first the amorphous catalysts produced a step change increase
FCC unit (Powdered Catalyst Louisiana No. 1, PCL1, 1942) in activity. The improved catalytic activity resulted in
in Baton Rouge, LA. By 1945, approximately 30 % of the liq- increased delta coke on spent catalyst requiring improved
uefied petroleum gas (LPG) and olefins being produced as regenerator metallurgy to withstand the increased combus-
feedstock for alkylation units had their source in the FCC. tion temperatures. Additionally, riser technology (plug flow
Following World War II, the striking advantages of the FCC tubular reactors) was incorporated into existing units to

1
Kyushu University, Kasuga, Fukuoka, Japan
2
INTERCAT, Inc., Vleuten, The Netherlands
3
JX Nippon Oil & Energy Corp., Yokohama, Kanagawa, Japan
4
Albemarle, Amsterdam, The Netherlands
5
Fuji Oil Company, Ltd., Sodegaura, Chiba, Japan
6
JGC Corp., Yokohama, Kanagawa, Japan
7
Chiyoda Corp., Kawasaki, Kanagawa, Japan
197
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198 Petroleum Refining and Natural Gas Processing

take advantage of the improved intrinsic activity and yield in Figure 9.1, the light fraction (that boils below 90 °C)
selectivities. The risers also served to minimize over-cracking contains much olefin, but little sulfur. Therefore, only the
and maximize gasoline production. heavy fraction (HCCG), where most of the sulfur is concen-
An additional FCC milestone was the inclusion of residue trated, is usually treated in the HDS unit. The properties of
feedstocks into the FCC feed slate. This was made possible HCCG produced from low sulfur atmospheric residue are
by unit design advances developed by Total Petroleum USA, summarized in Table 9.1 [11]. The CCG contains olefins,
Kellogg, and UOP. saturates, and aromatics. Internal and branched olefins are
The third major milestone in the development of the dominant in the olefins of CCG, but some n-olefins are also
process came as a result of rocketing propylene prices in the present. Concerning the RON drop, n-olefin HG causes more
mid-1990s, transforming the FCC into a platform for produc- concern than the HG of branched olefins.
ing maximum propylene yield. This led to the development The GC-AED analysis of this HCCG is shown in
of the DCC (deep catalytic cracking) process (Sinopec and Figure 9.2 [11]. Alkylthiophenes, alkylbenzothiophenes,
Shaw Stone & Webster), RxCat process (UOP), and the alkylthiocyclopentanes, and disulfides are identified on the
Superflex (Kellogg) unit. chromatogram. Table 9.2 shows the composition of these
sulfur compounds [11]. The total amount of alkylthiophenes
9.2.2 Low Sulfur Gasoline Production from FCC is about half of alkylbenzothiophenes. These results agree
Products with a report analyzing the CCG containing 1000 massppm
9.2.2.1 Introduction sulfur [12].
Catalytically cracked gasoline (CCG) produced from FCC CCG is hydrodesulfurized on a Co-Mo/g-Al2O3 catalyst
of vacuum gas oil (VGO) or atmospheric residue supplies under the following conditions: 200–290 °C, 1.6 MPa, liquid
one of the major components of motor gasoline produced hourly space velocity (LHSV) 3.5–10/h, and H2 /feed ratio
in a refinery. CCG containing high levels of sulfur requires 338 NL/L. The composition of the sulfur compounds in the
hydrodesulfurization (HDS) to reduce the sulfur levels for HDS products of CCG are shown in Table 9.2. After HDS,
compliance with environmental regulations. It is important, the total sulfur content decreased from 229 ppm to 81 ppm
however, to note that CCG contains 20–40 vol % olefins and at 220 °C, whereas 17 ppm of thiols were produced in the
using the current naphtha HDS process would reduce the reaction. The thiols produced in CCG HDS are not interme-
octane number (e.g., Research Octane Number [RON]) due diates from the HDS reactions of sulfur compounds. Thiols
to the hydrogenation (HG) of olefins in the HDS process [9]. are produced by the reactions between H2S and olefins
Therefore, a selective CCG HDS process providing higher HDS
activity and lower olefin HG must have been developed. In
2009, more than 100 CCG HDS units were operating in the
Table 9.1—Properties of CCG [11]
world, and the commercial units are mostly selective CCG
(Reprinted with Permission)
HDS except several demonstration units. This section focuses
on the properties of CCG and the desulfurization processes. Composition vol %
The catalysts used in CCG HDS are described in Chapter 28. Saturates 41.9

9.2.2.2 Analysis and HDS of CCG Aromatics 27.7

Main sulfur compounds in CCG are alkylthiophenes and Olefins 30.4
alkylbenzothiophenes. They are produced by the cracking
of heavier thiophenic compounds or newly produced by Olefins by structure
chemical reactions during FCC. Olefins are also produced 1-Olefins H2C=CR2 2.3
by the cracking reactions. Because beta-scission is a major
H2C=CHR 5.0
reaction pathway in catalytic cracking, theoretically, the
same amount of paraffins and olefins should be produced. Internal olefins HRC=CR2 9.8
A CCG is distilled to each 10 °C fraction and the amounts
HRC=CHR 13.3
of sulfur and olefin are measured (Figure 9.1) [10]. As seen
Isoolefin ratio in C=7% 78.9

300 Total sulfur massppm 229

Olefin vol % Sulfur massppm

200
Light Heavy Density 15 °C g/cm3 0.778
fraction fraction Research octane number 87.0
100
Distillation Temperature °C
0 IBP 48
80 10 % 88
60
30 % 110
40
20 50 % 136
0 70 % 165
40 60 80 100 120 140 160 180 200
Boiling Point ˚C 90 % 201
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Figure 9.1—Sulfur and olefin distribution in CCG [10]. EP 231

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Chapter 9 n Advances in Petroleum Refining Processes 199

Figure 9.2—Sulfur compounds in HCCG identified by GC-AED (see Table 9.2 for the peak identification numbers) [11]. Reprinted
with permission.

Table 9.2—Sulfur Compounds in CCG before and after HDS at Different Conditions [11]
(Reprinted with Permission)
Reaction temperature, °C

210 220
Feedstock
GC-AED No. Sulfur compound sulfur, ppm Sulfur, ppm Conversion, % Sulfur, ppm Conversion, %

1 Thiophene 7 4 43 3 57

5 Thiacyclopentane 5 2 60 1 80

3 2-methylthiophene 11 7 36 6 46

4 3-methylthiophene 10 5 50 3 70

6 2-methylthiacyclopentane 3 3 0 2 33
7 3-methylthiacyclopentane + 5 5 0 4 20
2-ethylthiophene

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10 2,3-dimethylthiophene 5 3 40 2 60

9 2,4-dimethylthiophene 7 5 29 4 43

8 2,5-dimethylthiophene + 4 2 50 2 50
3-ethylthiophene

11 3,4-dimethylthiophene 3 1 67 1 67

13 C3-thiophenes 15 15 0 12 20

14 C4-thiophenes 7 6 14 5 29

15 Benzothiophene 63 2 97 0 100

16 Methylbenzothiophenes 63 28 56 12 81

2 Dimethyldisulfuide 4 1 75 0 100

12 Diethyldisulfuide 1 1 0 0 100

Unknown 16 15 6 7 56

Thiols 0 22 17

Total sulfur 229 127 81

HDS% 45 65

Conversion% 54 72
Reaction conditions: Pressure, 1.6 MPa, LHSV 3.5/h, H2/feed ratio, 338 NL/L

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200 Petroleum Refining and Natural Gas Processing

contained in CCG. It is noted that alkylbenzothiophenes tested and a simulation model was studied [14]. The
are more reactive than alkylthiophenes, and the reaction reaction conditions were selected as follows: Temperature =
rate constant of benzothiophene is 6 times larger than that of 200–300 °C, pressure = 1.0–5.0 MPa, hydrogen/feed = 100–
thiophene. With the increasing number of alkyl substitution 500 m3/m3, and LHSV = 2–6 h−1.
groups, the HDS reactivity decreases. The 2-methylthiophene
is less reactive than 3-methythiophene because of the steric 9.2.2.3.1 Modeling Thiol Formation
hindrance of a methyl group substituted at the 2-position A thiol formation model is shown in Figure 9.5
of thiophene. The equilibrium constant for the reversible reaction in
The intrinsic reactivity of sulfur compounds contained the model is given by Eqs 9.1 and 9.2, as follows:
in CCG was examined by HDS of individual sulfur com-
pounds dissolved in toluene [11]. The obtained conversions Kp = [Thiol]/([Olefin][H2S]θ) (9.1)
at several temperatures are shown in Figure 9.3, indicating
that the reactivity decreases in the order benzothiophene Kp = exp((−ΔH + TΔS)/RT) (9.2)
> thiophene > 3-methylthiophene > 2-methythiophene
> 2-ethylthiophene > 2,5-methythiophene within the tem- where Kp is the equilibrium constant, [ ] represents each
perature range examined. It is noted that the order of the compound’s partial pressure, and θ is the H2S coverage of
reactivity is the same as that of sulfur compounds in CCG the catalyst surface, calculated from Eq 9.3
HDS. However, the rate of reaction of sulfur compounds in
toluene is much faster than that in CCG. It is considered that θ = K[H2S]/(1 + K[H2S]) (9.3)
olefins in CCG depress the HDS reactivity by competitive
adsorption on HDS active sites of the catalyst. where K is the equilibrium constant of H2S adsorption. In
During the HDS reaction, olefins in CCG are hydro- Eq 9.2, ΔH and ΔS denote the enthalpy and entropy of thiol
genated and RON is decreased (Figure 9.4). Because the formation, respectively. These are calculated employing the
decrease in RON is a serious problem in deep HDS, a selec- NASA thermochemical polynomials [15] shown in Eqs 9.4
tive HDS process is desired to preserve the olefins during and 9.5:
the reaction [13].
ΔH/RT = a1 + a2T/2 + a3T2/3 + a4T3/4 + a5T4/5 + a6/T (9.4)
9.2.2.3 Process Design of CCG HDS Using a
Theoretical Model ΔS/R = a1lnT + a2T + a3T2/2 + a4T3/3 + a5T4/4 + a7 (9.5)
Special reaction conditions should be carefully selected
for CCG HDS, because of thiol formation. CCG HDS was Each constant a1 through a7 was calculated using
THERGAS [16,17], which is a program for calculating the
100 thermochemical properties of organic compounds in gas
100 massppm S in toluene and liquid phase. In this case, the 2-methyl-1-hexylthiol was
thiophene
80 2-methylthiophene designated a model thiol compound. This thiol is a typical
Conversion, %

3-methylthiophene thiol contained in heavy CCG. For the CCG HDS, thiophene
60 2,5-dimethylthiophene
2-ethythiophene
HDS and olefin HG ratios are calculated from Eqs 9.6 and
benzothiophene 9.7, respectively.
40
CCG
−d[Olefin]/dt = [Olefin]n1[H2]m1A1exp(−E1/RT)
20
(1/(1 + α1[H2S]) (9.6)
0
130 150 170 190 210 230
Press:1.3 MPa −d[Thiophene]/dt = [Thiophene]n2[H2]m2
Reaction temperature, ˚C LHSV: 3.5/h
A2exp(−E2/RT)(1/(1 + α2[H2S]) (9.7)
Figure 9.3—HDS conversion of individual sulfur compounds
and CCG [11]. Reprinted with permission. In Eqs 9.6 and 9.7, A denotes the apparent frequency
factor and E the apparent activation energy. The sulfur and
olefin content in hydrotreated CCG can be estimated by
100
including these equations in the simulation model.
RON
Olefin hydrogenation %

87
9.2.2.3.2 Verification of the Simulator Model
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

86 Figure 9.6 shows the effect of temperature on the estimated

and experimental results for thiol production. The theo-
RON

50 85 retical calculations showed a good correspondence with

84
S H2
83 Thiophenes
Olefin hydrogenation H2S
0
R 2
R1 R2
0 50 100 R1 SH
Equilibrium constant Kp
HDS % Thiols

Figure 9.4—Olefin HG and reduction of RON by HDS [10]. Figure 9.5—A thiol formation model.
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Chapter 9 n Advances in Petroleum Refining Processes 201

12 20
Simulation Simulation
Thiolsulfur, mass ppm 10 Experimental results 16

Olefin HG, %
Experimental Results
8 12

6 8

4 4

2 0
100 200 300 400 500
0 H 2 / Feed, NL/L
180 200 220 240 260 280 300
Temperature, ° C Figure 9.8—The effect of H2 /feed in CCG HDS.

Figure 9.6—The effect of temperature on CCG HDS [19].

Reprinted with permission.
450
Inlet temperature 290 ˚C

Temperature, ˚C
the experimental results. It is clear that the higher the 400
temperature, the lower the thiol formation. In general, the
equilibrium constant Kp depends on the temperature; Kp 350 Simulation
decreases with the increasing reaction temperature. Experimental Results
300
The effect of pressure is shown in Figure 9.7. For most
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

HDS reactions, the higher the reaction pressure, the lower 250 Inlet temperature 215 ˚C
the sulfur content. In contrast, Figure 9.7 shows that the
sulfur content of hydrotreated CCG increases as the reaction 200
Inlet Reactor Position Outlet
pressure increases. This increase is attributed to the increas-
ing thiol production as the pressure increases, indicating Figure 9.9—The temperature profile in the reactor.
that a lower pressure is favorable for reducing the sulfur
content in hydrotreated CCG. In this case, the calculated
results agree very well with experimental results. Most of the 2004 and producing low-sulfur gasoline with sulfur level is
total sulfur in hydrotreated CCG derives from the generated less than 10 ppm. Figure 9.10 shows a photograph of ROK-
thiol. It is, thus, essential to set up a simulation model that Finer in Sendai, Japan. This process consists of a single
includes thiol formation. reactor system (Figure 9.11) and is used for low to middle
Most of ΔT comes from olefin HG in CCG HDS. The sulfur level CCG HDS.
olefin HG ratio is calculated by Eq 9.6. Figure 9.8 shows A selective CCG HDS catalyst is used in this process,
the effect of the hydrogen/feed on olefin HG. The theoretical where the whole CCG (WCCG) is separated into low-boiling
calculations showed a good correspondence with the experi- (LCCG) and high-boiling fractions (HCCG). The HCCG is
mental results. Figure 9.9 shows the reactor temperature hydrotreated in a fixed-bed reactor (Rx) and the effluent
profile for the reaction. In this case, the estimated results is sent to an amine unit for recovering H2S. The low-sulfur
obtained by the simulator agree with the experimental LCCG fraction is not hydrotreated to preserve the olefins.
results as measured in an adiabatic reactor [18]. The sweetening unit removes thiols produced in the HDS
reactor.
9.2.2.4 Selective Hydrodesulfurization The SCANfining process [20] developed by ExxonMobil
Processes for CCG and Akzo Nobel has two reactors, one for selective HG of
The selective CCG HDS process is the most widely used diolefin and the main reactor for selective HDS. Diolefins
process and over 100 units are being operated, under design,
or under planning. A selective CCG HDS catalyst is employed
in the main reactor to achieve deep HDS with low olefin HG.
The ROK-Finer [19] process has been developed by
Nippon Oil Corporation with three units operating since

70
60 Simulation
Sulfur, mass ppm

Experimental Results
50
40
30
20
Total Sulfur
10 Thiol
Thiophene
0
Base +1 +2 +3 +4
Pressure, MPa
Figure 9.7—The effect of pressure on CCG HDS [19]. Reprinted
with permission. Figure 9.10—ROK-Finer in Sendai refinery, Japan.
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202 Petroleum Refining and Natural Gas Processing

Make up H2 The tightening of sulfur specifications of diesel fuel requires

deep desulfurization of diesel feed streams.
Bleed Gas Off Gas The problem of deep desulfurization has become more
serious due to the increasingly more stringent limits of
Rx sulfur content in finished fuel products, while the sulfur
Amine
section contents of crude oils have been increasing. The shift from
Fu Stabilizer normal to deep desulfurization introduces complicated
technical issues. Many factors such as the catalysts, process
parameters, and the nature of sulfur compounds present in
the feed can have a significant influence on the degree of
Tw desulfurization of diesel feeds. Among these, the feedstock
WCCG
quality plays an important role on deep desulfurization
Sweetening because the types of sulfur, nitrogen, and aromatic com-
section Product pounds and their concentrations are different in different
HCCG feedstocks.
LCCG
Diesel fuel feedstocks mainly consist of middle distil-
Figure 9.11—ROK-Finer process flow. lates in the boiling range of 220–360 °C. Straight-run gas
oil obtained from atmospheric distillation of crude oil and
their blends with the cracked middle distillates such as light
cause fouling problems in the heat exchanger and the HDS cycle oil and coker gas oil are extensively used in diesel
reactor. Therefore, they are hydrogenated in the selective fuel production. These feedstocks usually contain different
hydrogenation reactor. amounts of sulfur, nitrogen, and aromatic compounds.
The Prime-G+ (Axenes-IFP) process [21] has three reac- Distributions of sulfur compound types in different blending
tor units, for selective hydrogenation of diolefin, for the streams are also different. The contents of the least-reactive
main selective HDS, and a finisher. The finisher is a unique sulfur compounds in the feeds depend to a large extent on
reactor system in which thiol is decomposed into H2S and the end boiling point of the feedstock. This section overviews
an olefin at high temperatures (over 300 °C). Prime-G+ can deep desulfurization of diesel fuels in terms of catalysis and
even be applied to high-sulfur-level CCG. chemistry as well as processes.
In the light CCG, thiols, sulfides, and other sulfur com-
pounds are included. In the case of high-sulfur-level CCG, 9.3.2 Designing Approaches to Deep
some treatment of LCCG is necessary. The CDHydro pro- Desulfurization of Diesel Fuels
cess [22] developed by CDTech and the OATS process [23] Approaches to ultradeep desulfurization include: (1) improv-
developed by BP convert these sulfur compounds into large ing catalytic activity by new catalyst formulation for HDS of
molecules by reaction with olefin or diolefin and transfer 4,6-dimethyldibenzothiophene (4,6-DMDBT); (2) increasing
them to HCCG by distillation. As CCG HDS products contain operating severity; (3) revamping existing unit including
thiols, a sweetening process is often added for posttreatment. internals; (4) designing new reactor system; and (5) developing
The other processes including OCT-GainTM [24] devel- new processes. One or more approaches may be employed
oped by ExxonMobil and ISALTM [25] developed by INTE- by a refinery to meet the challenges of producing ultraclean
VEP and UOP are HDS processes with octane value fuels at affordable cost.
recovery section. CCG undergoes deep HDS in the first HDS Figure 9.12 shows the relative volume of catalyst bed
section where olefins are hydrogenated completely. In the required for achieving various levels of diesel sulfur using
next section, octane value is recovered by the isomerization conventional HDS of gas oil over a commercial hydrotreating
and alkylation of the paraffins. catalyst [28].
The S-ZorbTM [26] developed by Phillips Petroleum Co. The modeling is based on HDS using a commercial
is an adsorption process in which a metal base solid sorbent catalyst for the production of 500 wtppm sulfur diesel. In
is used. The sorbent extracts sulfur compounds in a fluid-bed this simulation, Middle East straight-run gas oil containing
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

reactor and some sorbent is constantly regenerated in the 1.0 wt % sulfur was selected as a feedstock. Hydrogen partial
regenerator. pressure, reaction temperature, H2 /oil ratio, and other condi-
Other HDS processes are also proposed and well tions were the same as those for the commercial desulfur-
reviewed in previous reports [27]. ization (500 wtppm sulfur level).
According to this simulation, the amount of catalysts
9.3 Deep HDS of Diesel Fuels must be increased by a factor of 2.5 to achieve deep desul-
9.3.1 Challenges in Deep Desulfurization of furization (50 wtppm sulfur level) and by a factor of 4.5
Diesel Fuels for ultradeep desulfurization (10 wtppm, for example). The
The production of environmentally conscious low-sulfur second-generation catalyst has been reported to obtain about
diesel fuels has been of high priority in the petroleum refin- 1.3 times higher activity than those of the first-generation
eries in the world. This is because environmental regulations catalysts. Ultradeep desulfurization would require over
have been introduced in many countries around the world three times more amount of the second-generation catalyst
to reduce the sulfur content of diesel fuels to very low levels. compared to the production of 500 wtppm sulfur diesel
Limiting the sulfur levels of diesel and other transporta- by the same catalyst. To accommodate this amount, it is
tion fuels to very low levels are certainly beneficial from an necessary to add two or three reactors. If the reaction tem-
environmental point of view, but it poses major operational perature is increased by about 20 °C, the amount of catalysts
and economic challenges in the petroleum refining industry. needed would be twice as much as the amount used in the
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Chapter 9 n Advances in Petroleum Refining Processes 203

Figure 9.12—Simulation of sulfur content in diesel desulfurization [28]. Reprinted with permission.

production of 500 wtppm sulfur diesel, requiring one more 4. Density

reactor. An increase in reaction temperature would cause For decreasing sulfur levels from 500 wtppm to 50
deterioration of the color of the product, and shorten the wtppm and from 500 wtppm to 10 wtppm, respectively,
catalyst life, because of the deposition of coke on catalyst by increasing the reaction temperature, the density of
surfaces. The catalyst life is an important factor for the pro- the product decreases by 0.003 g/cm3 and 0.005 g/cm3,
longed continuous operation and cost efficiency. respectively.
5. Cetane index
9.3.3 Improving the Catalytic Activity For decreasing the sulfur level from 500 wtppm to
Design approaches for improving catalytic activity for 50 wtppm and from 500 wtppm to 10 wtppm due to
ultradeep desulfurization focus on the more effective removal increase in reaction temperature, the centane index of
of 4,6-DMDBT by modifying catalyst formulations through product increases by 1 and 2, respectively.
(1) enhancing the hydrogenation of aromatic ring in 4,6- 6. Pour point
DMDBT by increasing hydrogenating ability of the catalyst; The pour point of the product is not improved by deep
(2) incorporating acidic feature in the catalyst to induce isom- desulfurization up to a sulfur level of 10 wtppm.
erization of methyl groups away from the 4- and 6- positions; 7. Total aromatics content
and (3) reducing inhibiting effects of some substances (such as In case of deep desulfurization to reduce the sulfur
H2S). Tailoring the reaction conditions must be optimized for level from 500 wtppm to 50 wtppm by increasing the
specific catalytic functions [29]. New catalyst formulation and reaction temperature with any LHSV, total aromatics
commercial catalyst development are discussed in Chapter 10. content of product decreases by 2–3 vol %. In case of
reducing the sulfur level from 500 wtppm to 10 wtppm
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

9.3.4 Increasing the Severity of Operation by increasing the reaction temperature with LHSV of
Operating parameters, such as reaction temperature, play a lower than 1 h−1, total aromatics content of product
significant role on the degree of desulfurization and affect decreases by 7 vol %. In contrast, in case of reducing
the properties of the HDS products, such as sulfur content, the sulfur level from 500 wtppm to less than 50 wtppm
color, aromatics content, density, cetane index, and pour by increasing the reaction temperature with LHSV of
point. Such changes in the properties are briefly described higher than 2 h−1, the total aromatic content tends to
below [30]. increase. Therefore, high pressure and low LHSV are
1. Sulfur content required to decrease the total aromatics content.
To achieve deep desulfurization of sulfur level from 8. Polyaromatic aromatic hydrocarbons (PAH) content
500 wtppm to 50 wtppm and from 500 wtppm to 10 Regardless of degree of desulfurization, ranging from
wtppm, temperatures should be increased by 16–18 °C 500 wtppm to 10 wtppm, PAH content remains almost
and 28–31 °C, respectively. the same. To decrease PAH content, high pressure is
2. Color required.
In case of deep desulfurization (sulfur level: 500 9. Distillation properties
wtppm), Saybolt color of product ranges about +20 in Regardless of degree of desulfurization, ranging from
any contact time (LHSV). However, it is expected to get 500 wtppm to 10 wtppm, temperature of 90 vol % dis-
worse by higher severity such as higher reaction tem- tillation remains almost the same. Deep desulfurization
perature under high LHSV conditions. is not expected to improve the distillation properties.
3. Chemical hydrogen consumption
For decreasing the sulfur levels from 500 wtppm to 50 9.3.5 Revamping an Existing HDS Unit
wtppm and from 500 wtppm to 10 wtppm, the chemi- Ultradeep desulfurization would inevitably require modifi-
cal hydrogen consumption increases by about 10 Nm3/ cation or renewal of existing equipment, unless significant
kL and 20 Nm3/kL, respectively. improvement is achieved in the performance of catalysts.
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204 Petroleum Refining and Natural Gas Processing

To minimize the cost of modification, it is important not sulfur compounds, which should occur in the major
only to improve the equipment but also to take steps on the downstream part of a co-current trickle-bed reactor
process side, such as the maximization of the operation during deep desulfurization [29]. The normal co-current
efficiency of existing equipment and the optimization of trickle-bed single reactor is, therefore, not the optimal
operating conditions. Tailoring process conditions aim at configuration for deep desulfurization. A new reactor
achieving deeper desulfurization with a given catalyst in an design involves two or three catalyst beds that have both
existing reactor without changing the processing scheme, co-current and counter-current flows. The beds can be
with minimum capital investment. The parameters include accommodated in a single or two to three reactors as
some relatively minor changes in processing scheme or some shown in Figure 9.13. This new design was proposed
capital investment (such as expansion in catalyst volume or by ABB Lummus and Criterion, as represented by their
density, H2S scrubber from recycle gas, and improved vapor- SynSat process [31,32]. The hydrogen is mixed togeth-
liquid distributor). Any new capital investment (space velocity, er with the distillates at the entrance of the traditional
temperature, pressure) must be avoided. reactor and flows through the reactor together with the
The conditions for ultradeep desulfurization are oil in the reactor. The disadvantages of this kind of flow
expected to increase H2 consumption and the H2 /oil ratio, include having the highest H2 concentration at reactor
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

reflecting the influence on the catalyst life. The increase inlet and the lowest H2 concentration at the outlet.
in the H2 /oil ratio as well as installation of more reactors The H2S concentration has the reverse trend, creating
would result in an increase in the pressure loss in the hydro- unfavorable conditions for the deep HDS in the last part
gen gas recycle system. Therefore, such alteration would of the reactor. The solution to this problem is to design
require modification and/or renewal of existing equipment. a counter-current reactor as proposed by SynSat, where
Usually, the make-up hydrogen compressor and the recycle fresh H2 is introduced at one end of the reactor and the
hydrogen compressor may be upgraded by the replacement liquid distillate at the other end. Here, the hydrogen con-
of motors and other partial modification. These compres- centration is highest (and the hydrogen sulfide concen-
sors must be replaced, if the new conditions lead to a tration is lowest) where the most difficult-to-desulfurize
significant increase in hydrogen gas flow or pressure drop. sulfur compounds, such as 4,6-DMDBT are removed.
If the operating pressure in the existing units, such 2. Under-cutting of feedstock
as the heating furnace and heat exchanger, would exceed While many species of sulfur compounds are con
the design limit, these units must also be replaced. Such tained in diesel oil, the difficult-to-desulfurize com-
replacement would inflict a considerable increase in the pounds are mostly contained in the heavy end (high
cost of modification. boiling point range) as shown in Figure 9.14 [33]. Alkyl-
dibenzothiophenes, such as 4,6-DMDBT, are extremely
9.3.6 Designing a New Reactor System difficult to desulfurize, and these compounds are mostly
1. Counter-current flow system found in the fractions above 340 °C boiling point.
The reactor design and configuration involve both Straight-run gas oil is first fractionated into the fraction
one- and two-stage desulfurization. The H2S and NH3 containing mostly easy-to-desulfurize components (light
produced by hydrotreatment strongly suppress the gas oil) and that containing mostly difficult-to-desulfurize
activity of the catalyst for converting the refractory components (heavy gas oil), and each fraction is then

Figure 9.13—A schematic diagram of the SynSat process [31,32]. Reprinted with permission.
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Chapter 9 n Advances in Petroleum Refining Processes 205

Desulfurization is conducted with H2 /oil of 150–200

Nm3/kL for light gas oil and 250–500 Nm3/kL for heavy gas
oil. Thereafter, both are treated in the same separation unit.
Milder treatment conditions may be selected for heavy gas
oil by using the following method: The light gas oil, which
is not prone to colorization, is subjected to ultra deep
desulfurization at high temperature over 360 °C down to 5
wtppm or less, and the heavy gas oil is treated under milder
conditions down to about 30 wtppm [34]. In cases where
the existing equipment of the HDS unit is to be modified,
the existing reactor may be used for the desulfurization of
light gas oil, while the relatively small quantity of heavy gas
oil may be treated in a newly installed reactor. The increase
in pressure drop and the increase in compressor load can be
mitigated in this way, providing an opportunity for select-
ing a more economic path for equipment modification.
The integration with VGO HDS unit or a hydrocracking
unit may expand the operation range of the diesel oil desul-
furization unit, enabling efficient production of ultra low
sulfur diesel. The above system was evaluated more quan-
Figure 9.14—Types of sulfur compounds as a function of titatively in the case of producing ultra low sulfur diesel by
boiling range [33]. Reprinted with permission. using an existing HDS unit [35].

9.3.7 Developing New Processes

desulfurized under appropriate conditions. Depending on 1. Adsorption process
the type of crude oil, fractionation of straight-run gas oil at In advance of commercial scale unit results from its
320–340 °C results in the production of heavy gas oil in a Borger refinery application of Phillips’ S-Zorb process,
proportion of 10–20 vol % to the amount of straight-run diesel sulfur removal technology has been demon-
gas oil, and this heavy gas oil contains concentrated levels strated in a small-scale test unit to produce diesel feed
of difficult-to-desulfurize sulfur compounds. The heavy with less than 10 wtppm sulfur [36]. Diesel feeds ranged
gas oil is desulfurized effectively to remove 4,6-DMDBT, if from 500 to 3,300 wtppm sulfur containing a mixture of
the reaction is conducted using higher H2 /oil ratio, higher hydrotreated and straight-run gas oil and LCO. Mixing
hydrogen partial pressure, and longer reaction time as was determined to evaluate the process requirements if
compared with the desulfurization of straight-run gas oil. off-road diesels were specified at the same sulfur levels
On the other hand, the light gas oil can be desulfurized as on-road diesel, and if an existing diesel HDS were shut
under the conditions that are the same as or milder than the down when S-ZorbTM was installed. Figure 9.16 shows
conditions for the desulfurization of the typical straight-run a schematic flow diagram of the S-ZorbTM process.
gas oil. In each situation, net H2 consumption is reduced, in
Figure 9.15 shows the conceptual diagram of the HDS comparison with conventional HDS, because hydrogen
system to desulfurize two streams of feedstocks. After the is not used for desulfurization. In addition, the unit
fractionated light gas oil and heavy gas oil are fed into sepa- operates in a temperature region 38 to 66 °C above con-
rate reactors, the total H2 /oil ratio is set at 200–300 Nm3/kL. ventional HDS (371 to 454 °C), and at lower pressures

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 9.15—A conceptual flow scheme for HDS of undercut feedstock [34]. Reprinted with permission.
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206 Petroleum Refining and Natural Gas Processing

Figure 9.16—A schematic flow diagram of the S-Zorb TM process [36]. Reprinted with permission.

(up to 3.5 Mpa), and with minimum hydrogen partial hydrogen peroxide and a liquid phase catalyst, sulfur-
pressure. Under these conditions, 2- and 3-ring aro- containing hydrocarbons are converted to sulfones
matics are in equilibrium with their partially saturated that are adsorbed in an alumina bed, then recovered
counterparts, rather than being saturated, as they would in methanol. Reaction proceeds with a mechanism as
be in conventional packed bed HDS. Net hydrogen con- shown in Figure 9.17.
sumption without untreated LCO in the feed blend can Other than treating the sulfones, which could be done
be essentially zero. at another location, no hydrogen or hydroprocessing
Sulfur is removed by the partially sulfided adsor- is required for this process. Thus, the process could be
bent with no requirement for hydrogen consumption located at a pipeline terminal and used to process inter-
other than the minimum amount required to replace face materials that do not meet ultra-low sulfur diesel
the sulfur in the bonds with carbon molecules. This specifications.
is a ring-opening reaction as sulfur is removed from Another approach is to process current 500 wtppm
the thiophene molecules, and cetane improvement sulfur diesel to produce ultra-low sulfur diesel (ULSD).
results. The oxidation process is selective toward reactions
Hydrogen is necessary to stabilize the catalyst system with the highly substituted dibenzothiophene, and thus
and to partially saturate the nonequilibrium aromatics complements the existing fixed bed HDS processes.
in untreated LCO. Sulfur is removed from the diesel by Stanislaus et al. [38] have reviewed the recent
the adsorbent, not H2. Of course any cetane upgrading advances in the ULSD production. An overview of
that may be achieved by aromatics saturation is also recent approaches to deep desulfurization for ultraclean
eliminated. fuels was provided by Song [39]. Whitehurst et al. [40]
2. Oxidative process discussed the challenges for HDS of polyaromatic sulfur
Unipure, working with ChevronTexaco and Mustang compound, and Babich and Moulijn [41] reviewed
Engineering, has developed an effective process for the science and technology of novel processes for deep
oxidation of sulfur compounds in diesel fuels [37]. Using desulfurization of refinery streams.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 9.17—A reaction mechanism for oxidative desulfurization.
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Chapter 9 n Advances in Petroleum Refining Processes 207

9.4 Advances in VGO Hydroprocessing hydrogen rate of 150–500 nl/litre and hydrogen consumption
There are principally three major fixed-bed processes in of 40–120 nl/litre The MHC process option is typically applied
VGO hydroprocessing: FCC-pretreating (FCC-PT), mild to a low to medium conversion (<50 %) HC process, operat-
hydrocracking (MHC), and hydrocracking (HC). This section ing at a relatively moderate pressure as an FCC-PT at 35–100
focuses on the latest advances in hydroprocessing of VGO. bar, and often using a start-of-run temperature of 380oC or
FCC-PT is a trickle-bed hydrotreating process to reduce higher. The main objective of MHC process is to gain more
VGO sulfur initially from 1.0–3.0 wt % in the feed to typi- naphtha and distillate of lower sulfur content from the VGO
cally 0.1–0.3 wt % range in the product; consequently, a HDS hydrotreater while producing a high-quality FCC feedstock.
conversion of approximately 90 % is expected. The primary The latest VGO hydrotreating technologies developed
objective of FCC-PT is to produce a high-quality VGO feed- by the licensors are summarized in Table 9.3. One of the
stock having a higher hydrogen content and lower sulfur notable process developments is UOP’s APCU (advanced
content for the subsequent FCC unit while finally reducing partial conversion unicracking) technology. The process
the sulfur oxide emission from the refinery. The process nor- produces a high-quality FCC feedstock, in an MHC type of
mally applies an operating temperature of 330–400oC, LHSV operation, while simultaneously producing a higher cetane
of 0.3–2.0 h−1, hydrogen partial pressure of 35–100 bar, inlet ULSD through hydrotreating the enhanced hot separator

Table 9.3—VGO Hydrotreating and MHC Processes from Various Licensors

Process Licensor Pressure Catalyst Characteristics

Go-fining [42] ExxonMobil Wide Unspecified VGO hydrotreating with a variety of feeds of virgin,
range thermally cracked, cat cycle, and deasphalted oils
for sulfur and nitrogen removal, conversion to clean
products (MHC), and better-quality FCC feedstock.
Advanced Go-fining/FCC modeling, design flexibility
around feed fouling through proprietary internal
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

by-pass design and by-passable guard reactor.

Unionfining/APCU UOP < 100 bar Specific APCU at a moderate conversion of 20–50 % for ULSD
[43,44] pretreating and and FCC feedstock.
unicracking High-sulfur feeds of VGO and HCGO are treated with
catalysts high activity pretreat catalyst and distillate-selective
Unicracking catalyst.
The distillate product is separated via an EHS,
subsequently hydrotreated in an APCU finishing
reactor for high-cetane ULSD.

ISOCRACKING [45–47] CLG Wide Unspecified ISOCRACKING or optimized partial conversion.

range ISOCRACKING by SSOT, single-stage recycle (SSREC),
or TSR.
SSOT used to produce high-quality FCC feedstock or
high viscosity index (VI) basestock, and SSREC and TSR
for clean naphtha and distillate fuels. SSOT can be
revamped to partial or full recycle TSR using reverse-
stage ISOCRACKING with an additional smaller reactor.

CFHT/HyC-10 [48,49] Axens/IFP Wide NiMo-Alumina Once-through VGO hydrotreating (CFHT) or partial
range of HR548 and hydrocracking MHC process (HyC-10) to produce low-
HR568 sulfur FCC feedstock while producing ULSD in the
NiW-ASA of downstream polishing reactor section. Applicable
HDK776 specific EquiFlow distributor and quenching device.

IsoTherming [50,51] DuPont Wide Applicable Diesel/VGO hydrotreating or MHC using liquid phase
range conventional reactor in which hydrogen is dissolved in liquid,
hydrotreating and no gas passes through catalyst-bed. Hydrogen
or MHC is supplied by recycling liquid product, and the
catalysts adiabatic temperature rise is much less (isothermal)
than trickle-bed. Cost is expected to be lower due to
lack of recycle compressor and high-pressure vessels.

Syn Technology [52–54] ABB Lummus, Typically Specialized Hydroprocessing middle distillates including coker
Criterion and SGS 35–70 bar SynCat from and visbreaker gasoils, and heavier feeds in the
Criterion co-current and/or counter-current reactors with an
interstage HP stripper to remove H2S, NH3, and light-
ends from the liquid. Syn technology includes SynHDS
for deep HDS, SynShift for cetane improvement and
density reduction, SynSat for aromatic saturation, and
SynFlow for cold flow improvement.
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208 Petroleum Refining and Natural Gas Processing

(EHS) product in the APCU finishing reactor in the same In line with the catalytic activity enhancement described
high-pressure loop. Chevron’s ISOCRACKINGTM process above, the importance of reactor internals has gradually
technology provides a CFHT (cat-feed hydrotreating) and been recognized to fully utilize the credit provided by
MHC process approach through a single-stage once-through increased catalytic performance. The licensors have paid
(SSOT) configuration. They claim that an SSOT unit can considerable attention to developing better reactor internals
be revamped to a partial or full recycle mode in two-stage especially since the 1990s. One of the commercially available
recycle (TSR) configuration by applying a Reverse Stage unique inventions is Albemarle’s PLEX distributor device
ISOCRACKINGTM system with an additional small reactor. technology [55]. The PLEX technology includes D-PLEX
Axens/IFP developed the MHC process of HyC-10, wherein the (liquid distribution device), M-PLEX (liquid/liquid or gas/
product distillate from the downstream distillation column is liquid mixer), and Q-PLEX (gas/liquid quench and mixing
fed to a polishing hydrotreater with fresh hydrogen for ULSD device), where the innovation involves:
production. DuPont has developed IsoTherming process in • Enhanced liquid distribution uniformity by mini-
which the hydrogen is dissolved in a liquid and no gas passes mizing liquid entrainment present in the gas phase
through the catalytic bed. Consequently, the adiabatic tem- through distribution-unit redesign
perature rise observed is much less (more like isothermal). • Superior distribution at a wider range of liquid flows,
The latest noticeable progress in the VGO hydrotreat- which enables operation at liquid flow rates as low as
ing involves the following three technology elements: 20 % of the design rate
1. Catalytic technology in guard-bed and main-bed • Improved fouling resistance with additional capacity
2. Reactor internals of distributor tray and quenching for scale collection
devices The quench mixer, comprising sub-mixers in series
3. New reactor concepts to maximize utilization of cata- with equilibration after each sub-mixing, achieves highly
lytic activity efficient mixing of the fluids and gases. As a result, the
The guard-bed catalyst technology in the reactor top height of Q-PLEX distributor device becomes significantly
layer is very important to protect the main-bed catalyst compacted in relation to other commercial devices, as sum-
against fouling and catalyst poisons for optimizing the marized in Figure 9.19. Thus, PLEX technology improves
expected activity and cycle length. The guard-bed needs to the liquid/liquid and liquid/gas mixing in a more compact
collect the particulates to remove potential hot spot and device, which enables a smaller reactor or higher catalyst
pressure buildup, and also to protect the main-bed catalyst charge for higher performance.
from the various poisonous contaminants, e.g., Ni, V, Si, The distribution trays in use commercially are typi-
As, Na, Ca, and Fe. The catalytic grading and contaminant cally either perforated, chimney-type, or bubble-cap trays.
control technologies have been extensively improved in In the last decades, the licensors have developed several
the last decade so as to fully utilize the improved perfor- state-of-the-art distribution devices. The fundamentals in
mance of the main-bed catalytic technology. The catalytic the device improvement include uniform volumetric and
size and shape grading used in a given catalyst loading has thermal distribution of liquid and gas in the radial direction,
been particularly addressed and improved to effectively inter- and intramixing, quench performance, and fouling
trap particulates in addition to catalytic activity grading resistance. Various companies have been involved in the
technology for multiple contaminants trapping. Advances hardware modification and unique distribution devices have
in main-bed catalytic technology are also remarkable. The been developed. UOP invented a specific two-phase distribu-
catalytic activities have been improved 5- to 10-fold in the tion device using variable vapor-flow and liquid-flow rates
last decades compared to the classic technologies used in through given upflow channels to create a better mixing per-
the 1960s, as illustrated in Figure 9.18. Thus, the advances formance [56]. They also patented a specific reactor mixer/
of catalytic technologies in the guard-bed and main-bed are distributor of three circular trays and mixing chamber for
significant, and they are described in detail in Chapter 10. better quench liquid mixing [57]. ExxonMobil’s improved
Spider Vortex distributor technology relies on baffles
contained within the mixing chamber [58]. Chevron devel-
oped their own distributor and mixing devices involving
turbulent and circulating flow regimes [59]. The key tech-
nology characteristics of these latest developments are
summarized in Table 9.4.
Last, but not least, new reactor concepts are worthy of
discussion. Since the 1990s when low sulfur regulation was
enforced on a global scale, many researchers then started
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

to look more deeply into the HDS, HDN (hydrodenitro-

genation), and HDA (hydrodealkylation) reactions on the
molecular basis, to achieve an in-depth understanding of the
reaction chemistry so as to enhance novel catalytic and
process ideas. Mochida has conducted intensive research
on the inhibition effects of H2S and NH3 on HDS and HDN
reactions. His group has revealed that inhibition effects for
desulfurization of sterically hindered alkyl-substituted
sulfur compounds were much more pronounced than for
nonsterically hindered and nonalkyl-substituted com-
Figure 9.18—History of hydroprocessing catalytic activity [55]. pounds. Moreover, the HG (HYD) active site was much
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Chapter 9 n Advances in Petroleum Refining Processes 209

Figure 9.19—Device height to achieve same degree of mixing [55].

Table 9.4—Latest Developments of Concurrent Downflow Distribution Devices

Company Invention/Product Characteristics

Albemarle [55] PLEX distributor device PLEX technology of enhanced liquid-distribution uniformity by distribution
unit redesign, superior distribution at wider liquid flow range to allow a
liquid rate as low as 20 % of design rate, and improved fouling resistance.
Q-PLEX applies a specific swirl mixer for enhanced performance and lower
device height.

UOP [56] Two-phase distribution A plurality of distributor assemblies have fluid flow-paths with different
apparatus and process resistance to liquid flow by having vapor inlets of at least two different sizes
located on different assembly.

UOP [57] Hydroprocessing reactor / A quench fluid and downward-flowing liquid mixed by an apparatus
mixer/distributor comprising three circular trays and mixing chamber. Quench fluid and liquid
are admixed in a mixing chamber, a first distributor tray, and then second
tray of a plurality of mixing caps.

ExxonMobil [58] Distributing system for A distributor tray in multiple-bed downflow reactor comprising a collection
downflow reactors tray, mixing chamber, a first rough distributor tray, and a second final
distributor tray of a plurality of open-topped tubes with a side aperture.

Chevron [59] Distributor assembly for The distributor assembly comprising a centrally located mixing chamber, and
multi-bed downflow catalytic an annular collecting and mixing trough surrounding the mixing chamber.
reactors The mixing chamber mixes the liquid raining down from the catalyst bed with
a quench liquid and gas by circulating through the trough of turbulent and
circulating flow pattern, which later goes to the distributor tray.

M. Muller [60] Mixing device for two-phase The fluids flow through horizontal mixing box having at least one mixing
concurrent vessels orifice for the heat and mass transfer. Each mixing orifice is followed by
structure that divides the process stream into lower velocity streams, whereby
turbulent flow conditions are generated for heat and mass transfer.

Fluor [61] Reactor distribution and A quench zone mixing apparatus of low vertical height and improved
quench zone mixing mixing efficiency, with a swirl chamber, a rough distribution network, and a
apparatus distribution apparatus. In swirl chamber, reactant and quench fluids are mixed
by swirl action, and the mixture goes to rough distributor tray, and final tray
of a number of bubble caps for symmetrical fluid distribution.

Shell [62] Multi-bed downflow reactor Multi-bed downflow reactor comprising a) at least one device for injecting
liquid or gas for temperature control, b) liquid collecting tray, c) compartment
to receive gas, d) mixing zone of gas and liquid, and e) distributor tray.

Haldor Topsoe Two-phase downflow liquid Two-phase downflow distribution tray named “Vapor Lift Distribution Tray.”
[63,64] distribution device The tray has perforated evenly spaced holes across the surface with an
(vapor lift dist. tray) inverted U-shaped device of “Vapor Lift Tube.” The Vapor Lift Tube has similar
advantage to bubble-cap device of better gas-liquid mixing and has more
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
dripping points due to a smaller footprint for the improved performance.
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210 Petroleum Refining and Natural Gas Processing

more hindered than the Direct DeSulfurization site (DDS) treat-gas first at the lower half of the reactor, and then the
[65–67]. Mochida then developed better catalysts show- liquid is separated from the gases and is fed to the top of
ing much less inhibition via optimization of the catalytic the reactor with fresh hydrogen. Finally, the product is
Brönsted acid function and metal active sites for the first taken out of the middle of the reactor just above the feed
sour and the second sweet conditions in the two-stage inlet. This invention allows for reactions in the upper bed
hydrotreating process [67,68]. Yang [69] and Nakamura with fresh hydrogen to remove refractory sulfur effectively.
[70] reported that a CoMo-alumina catalyst was inhibited Mochida proposed a new, unique reactor concept with
more by NH3, whereas NiMo-alumina is affected more both co-current and counter-current flows in a reactor, as
by H2S. Egorova and Prins explained the adsorption of illustrated in Figure 9.20 [68]. The feed is introduced to an
amine compounds perpendicular to the catalyst sur- intermediate position of the reactor, and the hydrogen is
face hinders π adsorption of DBT and 4,6-DMDBT and introduced at the bottom of the reactor in an upflow mode.
thus the HYD pathway was more inhibited, whereas The lighter feed of easily removable sulfur compounds is
the occupation of sulfur vacancies by H2S inhibits the drawn upward with the upcoming treatgas in the upflow
DDS pathway [71]. All literature cited addressed that the co-current mode, and the heavier portion, containing the
inhibition effect of H2S and NH3 is significant, and their refractory sulfur, then flows downward in a counter-current
removal should dramatically increase the HDS and HDN mode with the upflow hydrogen. Mochida also proposed
reaction rates. suitable catalysts for each of the co-current and counter-
One of the noticeable process technologies to mini- current beds to offset inhibition of HDS reactions.
mize inhibition effects is Syn Technology licensed by ABB Consequently, various new reactor concepts have been
Lummus, Criterion and SGS, as summarized in Table 9.3. developed by several groups in order to minimize the H2S/
The process was developed for middle distillates, including NH3 inhibition effect and maximize the reactor performance
coker and visbreaker gasoils, and even heavier feeds in co- to produce high-quality products with reduced capital
current and/or counter-current reactors with an interstage investment. It is believed that such new reactor process
HP stripper. The feed is hydrotreated in the first co-current technology, in association with an in-depth understanding
reactor. H2S, NH3, and light-ends are stripped out from the of molecular chemistry, should greatly contribute to overall
liquid in the subsequent interstage HP Stripper, and the process performance improvement and the advances of
effluent is fed to the second reactor, which can be either catalytic reactor technologies.
of co-current or counter-current flow with fresh hydrogen.
This system looks to minimize the H2S/NH3 inhibition in 9.5 Advances in Solid Alkylation Process
the second reactor. This is particularly the case in the bot- for Motor Fuel Alkylate
tom of the counter-current reactor, which is an ideal envi- Alkylate, the gasoline boiling range product of the reaction
ronment for the remaining refractory sulfur and nitrogen of isobutane with light olefins (C3−C5), is an ideal gasoline
compounds to be removed. The licensor claimed different blend stock due to its high octane, low vapor pressure, absence
types of technologies, i.e., SynHDS for deep HDS, SynShift of toxic aromatics or reactive olefins, low sulfur, and paraf-
for cetane improvement and density reduction, SynSat for finic nature. Worldwide gasoline specifications continue to
aromatic saturation, and SynFlow for cold flow improve- force reductions in olefins, Reid vapor pressure, aromatics,
ment, by applying specific catalytic technologies. sulfur, and benzene. Many refiners would like to introduce
The multiple-stage hydrotreating process with an inter- alkylation units, which are well-established hydrofluoric
stage stripper or reverse treat gas-flow technology has been (HF) and sulfuric (H2SO4) liquid acid catalyzed alkylation
developed by several licensors. UOP has developed process processes, in order to meet severe gasoline specifications.
innovations with back-staged series flow reactors and EHS However, because both of these processes use corrosive
technologies [43]. UOP’s HyCycleTM Back-Staged reactor and potentially hazardous HF and H2SO4 liquid acid, many
configuration, wherein fresh hydrogen is routed first to the researchers have tried to develop solid acid catalysts as safer
hydrocracking reactor and then to a hydrotreating reactor, and more environmentally benign technologies.
uses a low per-pass conversion to minimize the undesired Some innovative processes coupled with solid acid
cracking reaction, and produce more high-cetane distillate catalysts to produce a paraffinic alkylate equivalent to the
with less hydrogen consumption. This process allows a 25 % product from liquid acid catalysts at a cost comparable to
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

lower pressure and a higher space velocity without sacrific- traditional liquid acid alkylation technologies have been
ing catalyst life and distillate quality. Chevron’s Single Stage developed and have resulted in commercial realization. The
Reverse Staging (SSRS) ISOCRACKING hydroprocesses a AlkyleneTM Process, the AlkycleanTM Process, the Fixed-Bed
recycled unconverted-bottom with fresh hydrogen in the Alkylation (FBATM), and ExSactTM Process apply unique
second reactor to produce high-quality diesel products and reactor systems as shown in Table 9.5.
achieve higher conversion with difficult feeds or reduced The AlkyleneTM process applies the transport riser reac-
reactor volume [72]. Chevron also patented a hydroprocess- tor coupled with a reactivation vessel as in an FCC process
ing method having at least two stages, wherein the second as shown in Figure. 9.21 [75]. The transport riser reactor is
stage reactor includes flash separation zones in between the used to reduce the degradation of alkylate product through
beds to strip out the treatgas and then introduce the efflu- side reactions by short contact time and the catalyst deac-
ent back with fresh hydrogen into the next bed [73]. tivation per pass by minimizing the deposition of heavy
Sie and De Vries invented a hydrotreating reactor in hydrocarbons on the catalyst.
which fresh hydrogen is introduced from the top of the Olefin feed is mixed with isobutane and is injected
reactor, and the fresh feed inlet and product outlet are into the bottom of the riser where it contacts with freshly
positioned at the middle of the reactor [74]. The process reactivated catalyst recycled from the regeneration vessel.
allows fresh feed desulfurization with high H2S and NH3 The reactants and catalyst flow up the riser where the
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Chapter 9 n Advances in Petroleum Refining Processes 211

Recycled Hydrogen

Rich H2S Vapor/Liquid

Separation/Recycle
Gas Oil System
Reaction Reaction
Time (min) Temp ( oC) Recycled
Hydrogen
Lighter
(No H2S)
Fraction 20 360 CoMo Con-current
HDS Zone Light

If Required Desulfurized Lighter

First Stage o
Fraction (<300 C)
Heavier Fraction NiMo
45 360 Yield=43 wt %
HDS Zone Counter-current

Second Stage
Heavier Fraction 10 360 NiMo
Color Removal Zone

Fresh Hydrogen
Diesel
Product
Mixing
Desulfurized Heavier Fraction (>300 oC)

Figure 9.20—New reactor design for deep HDS by Mochida [68]. Reproduced with permission.

alkylation reaction proceeds. Reactor effluent, which is

Table 9.5—Solid Acid Catalyst Alkylation separated from the catalyst by gravity at the outlet of the
Processes riser, flows out of the top of the reactor to the fractionation
Process Licensor Reactor Type section, and the catalyst falls by gravity into the regenera-
tion vessel, where it is reactivated by contacting with H2
AlkyleneTM UOP FCC Type
adsorbed in isobutene, so the heavy hydrocarbons are
AlkycleanTM ABB Lummus Global Swing Reactor hydrogenated and desorbed from the catalyst. With the
Akzo Nobel Catalysts riser, the feed isobutane to olefin (I/O) ratio could be kept
close to that used in traditional liquid acid alkylation.
FBATM Topsoe Fixed Bed A fixed-bed reactor of the FBATM process is shown in
ExSactTM Exelus Swing Reactor Figure 9.22 [76]. Olefin feed is mixed with both isobutane
and part of the reactor effluent and is introduced into the
top of the reactor. Recycling part of reactor effluent to
the reactor inlet has the two advantages of a reduction
of the temperature increase in the adiabatic reactor by
Alkylate decreasing the olefin concentration and the adjustment
of the reactor inlet temperature by cooling of the reac-
i-C4/H2 tor effluent. The typical external isobutane/olefin ratio
is 10. The olefins are converted into alkylate by a liquid
Reactivation superacid catalyst adsorbed on a solid support in the
Wash Zone fixed-bed reactor system. The FBATM process applies a
unique fixed-bed reactor system with a liquid superacid
catalyst adsorbed on a solid support and confined within
a mobile, well-defined catalyst zone. The reactor efflu-
ent is split into two streams, and the net reactor effluent
is sent to the effluent treatment section where traces
of dissolved acid and moisture contained in the reac-
tor effluent are completely removed. The acid-free net
Olefin Feed Isobutane Recycle reactor effluent is sent to the fractionation section and
the removed acid is sent to the acid recovery unit. The
Figure 9.21—Reactor of the Alkylene TM process (modified acid-soluble oil formed is selectively removed from the
after [75]). reactor system to maintain the catalyst activity and sent
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212 Petroleum Refining and Natural Gas Processing

Isobutane Isobutane acid processes. The product qualities of the solid alkylation
Recycle processes are equal to or slightly better than those of a sul-
Olefin Feed
furic acid process. The capital cost of FBATM is as much as
15 % lower compared with the sulfuric acid process without
on-site spent acid regeneration.
A process flow diagram of the AlkyCleanTM process is
shown in Figure 9.23 [77]. The process consists of four
Catalyst
Band
main sections: feedstock pretreatment, the reactor system,
catalyst regeneration, and product distillation The reac-
tor system operates in the liquid phase at a temperature
Solid Support range of 50–90 °C. The extensive refrigeration requirements
with Liquid associated with liquid acid processes are eliminated. The
Super Acid external isobutane/olefin ratio is in the range of 8/1 to 10/1,
comparable to the H2SO4 process.
Reactor Effluent A system of multiple reactors enables continuous alkyl-
ate production by cyclic operation between periods of
To and from alkylation and rejuvenation. The rejuvenation step removes
Acid Recovery Unit accumulated heavier molecular weight species that lead to
catalyst-pore plugging and deactivation. The zeolite catalyst
Figure 9.22—Reactor of the FBATM process (modified after [76]).
is reactivated by contacting with H2 adsorbed in liquid-phase
isobutane. The two reactors under cyclic operation allow
to the acid recovery unit. The recovered acid is returned for continuous production of alkylate, and the third reactor
to the reactor section. operates as an additional swing reactor where the slowly
The alkylate quality and yield from AlkyleneTM is shown deactivated catalyst during the cycle operation is regenerated
in Table 9.6 in comparison with those of traditional sulfuric in vapor phase with H2 at a moderate temperature (250 °C).

Table 9.6—Comparison of the Alkylate Product Octane and

the Economics of the Alkylene Process and the FBA Process with
Traditional Liquid Acid Process
Case 1 Case 2 Case 3a Case 4b

Alkylene FBA H2SO4 H2SO4

C5 + Alkylate Capacity BPSD 8,000 6,000 6,000 6,000

C5 + Alkylate RONG 95.0 96.1 96.0 96.0

MONG 92.9 93.2 93.1 93.1

(R + M)/2 94.0 94.6 94.5 94.5

Investment MM US$ 2.39c 34.00 50.00 40.00

Utilities US $/bbl 1.74 1.70 1.80 3.10

a
With on-site regeneration
b
Without on-site regeneration
c
US $/bbl

Isobutane
Light Ends
Isobutane

Feed
Product
Distillation
Olefin Feed Reactor
Pretreatment System n-butane

Catalyst Product
Alkylate
Product
Catalyst
Regeneration

Figure 9.23—Process flow diagram of the AlkyCleanTM System (modified after [77]).
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Chapter 9 n Advances in Petroleum Refining Processes 213

When the catalyst and operating conditions are opti- the investment cost of the ExSactTM process is considerably
mized, the RON numbers of the alkylate are as high as 97 lower by greatly simplifying operation and reducing the
to 98. When the temperature is lowered from 65 °C to 55 °C, amount of equipment required. For example, the ExSactTM
the RON of the alkylate increases from 97 to 98.1. process requires only two reactors because of the long on-
Table 9.7 compares the economics of the AlkyCleanTM stream cycle time. The noble metal content of the catalyst is
process with the H2SO4 acid process. largely reduced because of the ability to perform a complete
The investment cost for the AlkyCleanTM process is regeneration at 250 °C.
11.8 % lower than for the H2SO4 unit.
A process scheme of the ExSactTM process consists of
feed treatment, two multistage fixed-bed reactors with
9.6 Residua Thermal Cracking—Eureka
multi olefin feed and a separation section. One reactor is
Process
The Eureka process is a commercially proven residue ther-
used for reaction, while the other is on catalyst regeneration.
mal cracking process to convert heavy residue to valuable
Alkylation cycle lengths are between 12 and 24 h, typically
light oil at a high residue conversion similar to that of cok-
12 h, followed by a 2-h regeneration cycle. Catalyst is regen-
ing technologies, and to produce petroleum pitch [79,80].
erated with hydrogen/hydrocarbon mixture at 250 °C. The
The pitch produced can be handled in its liquid state, which
reactor system operates at a temperature range of 60–90 °C
enables the refiners to keep the plant yard clean as well as
and a pressure of 20 barg. The external isobutane/olefin ratio
to charge a liquid pitch to the direct gasification scheme
is in the range of 10/1 to 15/1. Compared with other solid
[81]. Sodegaura Refinery of Fuji Oil Company, Ltd. (FOC)
acid catalysts and conventional liquid catalysts processes,
commenced the operation of the first commercial plant of
the Eureka in 1976 and has been successfully operating it
Table 9.7—Comparison of the Economics of over 30 years.
the FBA Process with the Traditional Liquid
Acid Process [78] 9.6.1 Process Description
Case 1 Case 2 A simplified flow diagram of the Eureka process is pre-
Alky Clean H2SO4 sented in Figure 9.24. A wide range of heavy residues
including Canadian bitumen and Venezuelan heavy oil can
C5 + Alkylate Capacity BPSD 10,000 10,000
be processed as feedstocks in the process [82].
C5 + Alkylate RONC 96.0 96.0 For processing, the feedstock is preheated to 340 °C
and sent to the bottom of the fractionator, where it is
Investment MM US $ 32.2 36.5
combined with recycle oil. The combined feedstock is sent

Fuel
Gas
BFW Compressor
Reactor

CLO

Cracking Heater
CHO
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Stabilizer

Vacuum
Residue Water Waste
Recycle Water

Preheater
Fractionator

Pitch Flaker

Pitch
Steam Superheater

Figure 9.24—A flow diagram for the Eureka process [82]. Reprinted with permission.
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214 Petroleum Refining and Natural Gas Processing

to the cracking heater and heated up to 470–490 °C. The Properties and use of liquid pitch: The homogenous and
heated and partially cracked feed is then supplied to one stable liquid pitch is withdrawn from the reactor section
of the two reactors, which are switched batch-wise in a and stably transferred to pitch flakers by pipelines.
specified schedule. The cycle time on a given reactor is 3–4 h When integrating the Eureka process with a gasifica-
because of the short reaction time. tion process, the hot liquid pitch, as it is, is transferred
In the reactor, both cracking and polycondensation and directly charged to the gasification process, and
reactions take place in the presence of the injected super- can be diluted with distillates to adjust a viscosity
heated steam (SHS). The ratio of the SHS to the vapour in specified for the gasification burners.
the reactor is in the range of 0.2–0.45. The SHS injected The pitch from the Eureka process that can be trans-
into the reactor is not only for supplying a part of the heat ferred as liquid at the rundown has stable properties, high
of reaction required, but to strip the cracked oil immedi- ratio of hydrogen to carbon compared with a petroleum
ately out of the reactor as a light product. coke, high heating value, high volatile matter content, a high
The reaction in the reactor proceeds at 30–80 kPa(g), Hardgrove Grindability Index, a high softening point, and
400–430 °C, which are lower than those of the other ther- better compatibility to coal. Characteristics of the Eureka
mal cracking processes. These mild reaction conditions pitch are presented in Table 9.8.
at the SHS injection give lower cracked gas yield as well. The Eureka pitch can be utilized for the following
The pitch reached to the specified softening point is blown applications.
down to the stabilizer and then continuously withdrawn to 1. Binder pitch: The Eureka pitch can be used as a
the pitch flaker. In case of the liquid pitch gasification, the binder for a metallurgical coke. The binder enables
pitch is transferred directly to the gasifier from the bottom the steel industry to utilize noncoking coal as an alter-
of the stabilizer bypassing the pitch flaker. native of expensive hard coking coal, thus to expand
From the reactor overhead, cracked gas and cracked and optimize its selection of coal blends. The pitch
oil vapour along with the steam are transferred to the frac- produced in the FOC’s Eureka unit is mainly utilized
tionator, where cracked gas, cracked light oil (CLO), and as a binder.
cracked heavy oil (CHO) are obtained. As the produced gas 2. Boiler fuel: Another practical utilization of the pitch
yield including LPG fraction is less than the fuel required was developed for a boiler fuel. Existing boilers can be
in the Eureka unit, LPG recovery section is not necessary, applied in solid pitch burning with minor modifications,
which is usually installed in coking processes to recover the due to the high heating value, high volatile matter, and
LPG from the large amount of cracked gas. The cracked high Hardgrove index (fragile) of the Eureka pitch.
gas is internally utilized as a fuel for the Eureka unit, after FOC’s captive boiler burns the solid pitch for their
sweetening the compressed gas. The CLO and CHO are utility supply.
usually hydrotreated to stabilize olefinic molecules, after 3. Gasifier feed: For gasification, the liquid pitch can
rundown from the Eureka unit. be charged directly to the gasifier [82]. A facility for
liquid-charge gasification costs less than that for
9.6.2 Advantages of the Eureka Process solid-charge gasification. Further, high H/C ratio of the
The Eureka process has design advantages including low Eureka pitch leads to more efficient gasification than
pressure, short reaction time, and steam injection, as that of petroleum coke.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
described in the previous section. The advanced design allows
the following advantages as key process performances. 9.6.3 Applications of the Eureka Process
High cracked oil, low gas, and low-pitch yields: High The Eureka process can be widely applied in the residue
conversions of residua are achieved by the Eureka conversion installed in a refinery and now expanded to
process under mild reaction conditions. This also
means to reduce the pitch yield, which is at a similar
level to that of the coking technologies. The Eureka
Table 9.8—Typical Pitch Properties
could attain the lowest gas yield and the highest liq-
uid product yield among the residue thermal cracking Properties Unit Pitch
technologies. Density g/cm3 1.20
Good product quality with less overcracking and poly-
condensation reactions: The Eureka reaction design Softening pointa ºC 225
depresses a formation of polycondensed molecules in Volatile matter % (mass) 40
the distillates; thus the cracked distillates are easily
hydrotreated. It can moderate the reaction severity in Heating value kcal/kg 8,800–9,200
the downstream hydrotreating and lead to high-quality Hardgrove index – 150–170
distillate products.
Solvent insolubles
Two years of continuous operation provided by extending
decoking cycle of reactor: Steam injection under the low n-Heptane Ins. % (mass) 76
pressure in the reactor makes the cracked oil immedi-
Benzene Ins. ditto 50
ately vaporized from cracked residue. Thus, the cracked
residue stays homogenous liquid, highly aromatic Quinoline Ins. ditto 15
without light oil, and stable with low propensity for cok-
H/C (atomic ratio) 0.80
ing reaction. As a result, 2 years continuous operation is
achieved without decoking the reactors.
a
Ring and ball method.

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AST-MNL58-11-0801-009.indd 214 3/12/13 2:12 PM

Chapter 9 n Advances in Petroleum Refining Processes 215

x1000 BPD G
2.6
BD O Naphtha
C LGO |
Crude D 22.1 33. 4 H 30.8
API : 32.7 U D Diesel
30.8
S
140 38.0
HGO 4.4
FCC

AR 1.1 V
56.5 VGO G
56.5 V 29.3 43.1 38.0
O
D LS Fuel Oil
| 0.0
U
H
CLO CHO D
VR 6.9 12.7 S HS Fuel Oil
26.9 0.0
26.9
Eureka Pitch
0.0 0.0 7.7

Figure 9.25—A residue upgrading scheme with Eureka.

upgrade the unconventional heavy oil to produce synthetic

Table 9.9—Impacts of Residue Upgrading crude. Some examples are given below.
in Refinery: Yield Comparison, with and The Eureka unit is operating in the Sodegaura Refin-
without Eureka Scheme, % (vol.) on Crude ery to convert the heavy residue to the distillate products
Scheme Scheme and to produce the pitch which is mostly shipped to the
with Eureka without Eureka Increments steel industry for use as the binder, and the remainder is
used as a boiler fuel in the refinery. Figure 9.25 presents a
LPG 2.7 2.7 0
s implified block flow diagram of the Sodegaura Refinery,
Naphtha 22.2 20.3 +1.9 and Table 9.9 summarizes the impact of installation of
Eureka on the refinery product slate toward zero high sul-
Jet fuel 19.3 19.3 0
fur fuel oil (HSFO) production.
Diesel 22.0 4.2 +17.8 An example of upgrader for Canadian Athabasca Bitu-
men is presented in Figure 9.26. In a heavy oil upgrader,
FCC feed (LSFO) 27.2 20.9 +6.3
one of the objectives is to maximize the liquid product
HSFO 0.0 31.4 -31.4 yield. Table 9.10 represents test results in the Eureka pilot
Pitch 5.5 − +5.5 plant indicating that the pitch yield is significantly reduced
by the SHS injection.

LPG
x 1000 BD
Recovery Off Gas to Refinery fuel

Crude 5.7
Bitumen Synthetic
Flasher
crude
Treated Cracked Oil

50 14.2 SR-VGO & 45.7

Cracked H2
Distillates
Hydrocracker
Vacuum
Flasher
Power &
Steam
Eureka Pitch Gasification
30.1 (1550T/D)

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- Figure 9.26—A bitumen upgrader with Eureka.

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AST-MNL58-11-0801-009.indd 215 3/12/13 2:12 PM

216 Petroleum Refining and Natural Gas Processing

Supported by the New Energy and Industrial Tech-

Table 9.10—Product Yield of Eureka for nology Development Organization (NEDO), an affiliated
Athabasca Bitumen VR organization of Japan’s Ministry of Economy, Trade and
Low SHS High SHS Industry, a 3-year research project was started in fiscal 2000,
case case which was the first study to apply area-wide pinch technol-
ogy analysis to a large industrial area in Japan.
Cracked Gas (C4 minus) 5.0 4.6

Naphtha (C5-190ºC) 7.3 7.5 9.7.1 Area-Wide Pinch Technology

Middle Distillate (190–360ºC) 20.8 20.1 The SSSP analysis technique uses the data obtained from
heat exchangers, such as steam heaters, reboilers, steam
VGO (360ºC plus) 29.4 35.8 generators, and condensers, etc., on the interface between
Pitch 37.5 32.0 the energy system and the process system in a single site
and analyzes the energy-saving potential by optimal effective
SHS=superheated steam.
utilization with the best heat recovery.
The R-curve analysis technique uses the data of an
9.7 Integrated Processes: The energy system, such as boilers, gas turbines, steam turbines,
Development of Energy Sharing in steam headers, and steam users in a single site. By using
Industrial Areas of Japan with Pinch this technique, the energy-saving potential can be analyzed
Technology by introducing the optimal gas turbine combined system.
In recent years, there has been a common understanding in Figure 9.27 shows the procedure for applying area-wide
Japan that there is little room for further energy reduction pinch technology to an industrial area composed of multiple
in major industrial fields such as oil refining and petro- sites. Initially, the operation data for the SSSP analysis and
chemicals. However, our recent studies have determined the R-curve analysis are collected from all the sites in the
that despite the very high efficiency of the individual sites industrial area, which are then analyzed with respect to each
in a complex, the potential exists for large energy savings single site by the SSSP analysis and the R-curve analysis.
by area-wide energy sharing. Area-wide sharing would The results of the analyses determine which site has the
make the best use of energy across a large industrial area highest performance and which site has the lowest perfor-
by utilizing surplus heat from one or more sites to provide mance from the point of view of energy saving. The data
energy for the others. As a result of the study, a successful are then combined and condensed into one virtual site and
energy sharing project was developed between two sites in then again analyzed by the SSSP and the R-curve analyses,
one of the major industrial areas in Japan. which eventually evaluate the total energy saving potential
In the 1980s, Linnhoff et al. [83] introduced the con- in an industrial area composed of multiple sites.
cept of “target before design” using pinch technology for During the studies of the major industrial areas in
the design of individual processes. Pinch technology for Japan with area-wide pinch technology, it became clear
Heat Exchanger Network (HEN) design was developed by that theoretically a large energy saving potential exists. The
Linnhoff and Hindmarsh [84]. Later, a HEN retrofit frame- results are shown in Table 9.11.
work was established based on the “process pinch” [85,86]
and “network pinch” [87] concepts. Over time, pinch tech-
nology has been applied to increasingly large and complex
sites, facilitated by the development of a variety of tools
and techniques to enhance the methodology and simplify
analysis.
Pinch technology had been applied to a single site to
analyze the process system and the energy system, whereas
area-wide pinch technology enables an entire industrial area
to be analyzed. The latter consists of two existing analysis
techniques: “Site Source Sink Profile (SSSP) analysis tech-
nique” [88,89], and “R-curve analysis technique” [90−92]. Figure 9.27—Analysis from single site to multiple sites.

Table 9.11—Energy-Saving Potential in the Industrial Areasa

Industrial area Chiba (kL/year) Mizushima (kL/year) Mizushima/Chiba (kL/year)

1 No. of sites 23 35 1.5

2 Integrated fuel consumption (Fuel + power) 2,880,000 3,785,000 1.3

3 Energy-saving potential by R-Curve analysis 510,000 1,002,000 2.0

4 Energy-saving potential by SSSP analysis 130,000 211,000 1.6

Total 640,000 1,213,000

Domestic crude consumption 1 day 2 days

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
a
Annual crude oil conversion is shown as kilolitres per year.
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Chapter 9 n Advances in Petroleum Refining Processes 217

Table 9.11 shows Chiba industrial area and Mizushima Of the eight projects selected, the leading project
industrial area. Chiba has 23 sites and its integrated fuel proposal was finally selected, with the cooperation of the
consumption, which is the sum of the fuel consumption corresponding sites, based on its economical efficiency. The
and the electrical power consumption in the energy system, amount of energy saving was a little more than 10,000 kL/
is 2,880,000 kL/year (annual crude oil equivalent). The year for two sites, namely those of FOC and Sumitomo
R-curve analysis determined that Chiba has potentially Chemical Company (SCC). FOC is a mid-size refinery with
510,000 kL/year of energy saving, while the SSSP analysis a considerable track record in undertaking improvements to
shows it to have a potential 130,000 kL/year of energy sav- make more efficient use of energy. SCC is a leading petro-
ing. Chiba, therefore, has the potential to save a total of chemical site that is adjacent to FOC.
640,000 kL/year of energy, which is equivalent to almost The SSSP analysis identified which heat region of
1 day of crude oil consumption of Japan. Table 9.11 also energy could be shared. Figure 9.28 shows the results of
shows the result for Mizushima. Mizushima’s energy-saving SSSP only for FOC. The left half of the chart in Figure 9.28
potential is equivalent to almost 2 days of crude oil con- led to the conclusion that FOC had a large energy saving
sumption of Japan. potential in the region below 120 oC. Although the heat
In comparison, Mizushima industrial area has 1.5 times below 120 oC could be recovered and collected, it could not
more sites than Chiba industrial area, but its integrated fuel be utilized adequately in FOC because the heat demand was
consumption is only 1.3 times larger than Chiba. In con- located only at a temperature higher than 120 oC, as shown
trast, the energy-saving potential of Mizushima is almost in the right half of the chart in Figure 9.28.
twice that of Chiba. The conclusion is that the equipment Once FOC and SCC were combined in the SSSP, it
in the energy system in Mizushima industrial area performs would produce a new possibility for energy sharing as
less efficiently than that in Chiba. The conclusion is shown in Figure 9.29. There were two energy-sharing cases:
supported by the fact that Mizushima industrial area was one case was the sharing of very low pressure steam and the
established well before that of Chiba. other case was hot water sharing. Eventually FOC and SCC
Data were collected from 1,222 heat exchangers from selected the hot water case and implemented the energy-
all the sites in Chiba industrial area, and many proposals sharing project between two sites.
for an energy sharing project were developed. After much FOC, SCC, and Chiyoda together developed a 3-year
discussion with the various sites, we could produce 8 feasi- business plan for the energy-sharing project and, with
ble project proposals using 31 sets of heat exchangers. The NEDO’s support, it was implemented in the second half in
energy saving from the 8 projects resulted in 90,000 kL/year. fiscal 2003 and completed in the summer of fiscal 2005.

Heating
media
300

Cooling
demand
250

200
Temperature, C
o

150 Cooling Heating

media demand

100

50 /CW

0
–400 –300 –200 –100 0 100 200 300

Enthalpy, MW
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 9.28—SSSP analysis for FOC.
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218 Petroleum Refining and Natural Gas Processing

300
Heavy line: Target
Broken line: Existing
250
Cooling
demand

Temperature, oC
200
Very low
pressure steam
150 recovered and
shared
Heating
demand
100
Exhaust heat
recovered
50 Hot water recovered
and shared

0
–1000 –500 0 500 1000
Enthalpy, MW

Figure 9.29—SSSP analysis for combined FOC and SCC.

The project successfully achieved its energy savings target

and, in recognition of this, the project was awarded a prize
by the Director-General of the Agency of Natural Resources
and Energy at the 27th Energy Conserving Machinery
Awards in January 2007.
Previously, the FOC and SCC sites had been operating
independently of each other; this was the first time for them
to have energy links. The energy-sharing project, shown in
Figure 9.30, consisted of two energy-saving systems and
an IT system. The two-energy saving systems were a heat-
sharing system and a low-heat power generation system.
The heat-sharing system achieved energy savings of
4,900 kL/year by collecting the exhaust heat from the cooling
water coolers in FOC and supplying it to SCC to reduce the
fuel consumption of the boilers. The project was monitored
by an IT system called an integrated energy monitoring
system, as shown in Figure 9.31, which sought the optimal
operating conditions and maintained and maximized the
combined energy savings for both sites of 4,900 kL/year. The
integrated energy monitoring system collected the operat-
ing information data and calculated the optimal operating Figure 9.31—Integrated energy monitoring system.
conditions, which could then be viewed independently by
both the FOC and SCC operators. The Level- model and two automatically started its calculations with real-time data at
site-specific Level 1 models calculated the optimal operat- 1-h intervals throughout the day, taking into account fuel
ing conditions of the inter-sites energy links. The system availability, heat and steam requirements, and the power
tariffs for each site.
The low-heat power generation system shown in
Figure 9.32 utilized the heat of the overhead vapor from
the distillation tower in FOC, which used to be cooled by air
fin coolers but was changed for the project so that the heat
of the overhead vapor exchanged with the high concentration
of ammonia solution at the vaporizer. Ammonia gas was
generated in the vaporizer at high pressure (3 MpaG), which
was then introduced into the turbine generator to produce
a maximum 4000 kW of electricity. This achieved an energy
saving of 5,600 kL/yr. The exhaust ammonia gas from the
turbine was led to a condenser and then the condensed
ammonia solution was sent back to vaporizer by a circu-
lation pump. This system has such a high autoregressive
performance that, despite being a closed system, unmanned
Figure 9.30—Implementation of energy-sharing project. operation could be established.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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AST-MNL58-11-0801-009.indd 218 3/12/13 2:12 PM

Chapter 9 n Advances in Petroleum Refining Processes 219

unused lower heat in the refinery and petrochemicals fields.

However, as unused lower heat exists in various other
fields, including steel, power plants, hot springs, and so
on, it is therefore important to develop the low-heat power
generation system so that it can be used in a wide range of
projects.

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--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Tokyo, July 23–28, 2006, http://www.parctech.com.
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10
Advances in Catalysts for Refining Processes
Isao Mochida1, Ray Fletcher2, Shigeto Hatanaka3, Hiroshi Toshima4, Shikegi Nagamatsu5, Makato
Inomata5, Rong He6, Richard S. Threlkel6, Christopher J. Dillon6, Junko Ida7, Toshio Matsuhisa7,
Shinichi Inoue8, Shinichi Shimizu8, and Kazuo Shoji9

10.1 Introduction bling beds in the reactor vessel for increased contact
The development and use of new catalysts has been a field time. Very high recycle rates of slurry were common.
of significant advances in the practice of petroleum refining • Zeolitic catalysts: The introduction of zeolite into syn-
in processes ranging from fluid catalytic cracking (FCC) thetic catalysts brought about one of the most significant
to hydroprocessing to increase the refining efficiency of and widespread changes observed in the refining world.
particularly challenging crude oils in producing the desired Nearly all catalytic crackers in the early 1960s (with the
distillate fuels with improvements in quality and perfor- exception of the Orthoflow B) were configured with a
mance, such as octane and cetane numbers, and compliance very short riser, which lifted the catalyst and oil mixture
with the increasingly strict environmental regulations. The through a plate grid into a reactor bubbling bed. Once
advances in catalysis include a more detailed characteriza- zeolites began commercially appearing in catalysts,
tion of catalysts, a more thorough understanding of the these units required reconfiguration to prevent exces-
chemistry on catalyst surfaces, new catalyst designs and sive coke make and overcracking of the gasoline.
manufacturing for increased activity and selectivity toward The unprecedented success of zeolite-based catalysts
desirable products, and increased cycle times for providing has been the result of the following characteristics [1]:
more favorable economics for catalytic processes. This • High activity,
chapter provides examples of new advances in catalysis in • Good activity stability,
parallel to the advanced processes discussed in Chapter 7, • High selectivities to gasoline versus coke and dry gas,
including processes such as FCC, hydrotreatment of FCC • Thermal and hydrothermal stability,
gasoline (catalytic cracked gasoline [CCG]), hydroprocessing • Reasonable accessibility,
of vacuum gas oil (VGO), alkylation, processing of heavy • Attrition resistance,
bottoms of crude oils, hydrogen production, and roles of • Resistance to poisons (metals, nitrogen, etc.), and
catalyst supports. • Acceptably low cost.
Typical FCC catalysts today are composed of zeolite,
10.2 FCC Catalytic Technology active alumina, clay, and binder [2]. One of the most sig-
The development of FCC catalyst technology has been equally nificant differences found among various commercially
as dramatic as the development of process designs. The first available catalyst systems is related to the binding systems.
FCC units were operated on clay-based catalysts. A transition These binding systems include silica sol, alumina sol, alumina
occurred to primarily alumina-based catalysts followed by gel, and in situ technologies. In situ technologies are based
inclusion of zeolites. A brief description of these technologies on the growth of zeolite crystal within spray-dried calcined
is as follows: clay microspheres.
• Clay-based catalysts: Beginning in 1942 and lasting • Zeolite: Typical catalysts today contain 30–40 % zeolite
through the early 1950s, most catalysts in use were with some formulations reaching 50 %. “Activity-
naturally occurring clays produced by crushing, drying, boosting” additives are currently available commercially
and sizing. Later, spray drying was introduced by Grace with zeolite concentrations of 60 % or more.
for improved fluidization. • Zeolite type: All Y zeolites begin as basically Na56[SiO2]136
• Synthetic catalysts: In the early 1950s, amorphous [AlO2]56*250H2O. They are produced via modification
catalysts with alumina as the primary component and optimization of synthesis conditions, treatment
were introduced into FCC units. These catalysts gave steps, and exchange agents and routes. The zeolite can
improved yield selectivities and higher diesel yields. be dealuminated thermally, chemically, or by using
The activities for the clay-based and synthetic catalysts both methods. Furthermore, the silica-to-alumina ratio
were low at approximately 25–35 wt %, requiring bub- (SAR) can be optimized to provide the extremes of
1
Kyushu University, Kasuga, Fukuoka, Japan
2
INTERCAT, Inc., Vleuten, The Netherlands
3
JX Nippon Oil & Energy Corp., Yokohama, Kanagawa, Japan
4
Albemarle, Amsterdam, The Netherlands
5
JGC Corp., Yokohama, Kanagawa, Japan
6
Chevron, Richmond, CA, USA
7
Sud Chemie, Shibuya, Tokyo, Japan
8
Chiyoda Corp., Kawasaki, Kanagawa, Japan
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9
Toyo Engineering Corp., Narashino, Chiba, Japan
223
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224 Petroleum Refining and Natural Gas Processing

maximum zeolitic activity (VGO operations), maximum hydrogen transfer catalytic systems via zeolite and active
zeolitic stability (residue cracking operations), plus an alumina improvements as well as enhancement of ZSM-5
innumerable number of intermediate levels. activity and stability.
• Rare earth: Rare earth (38) is added to the zeolite as an
activity enhancer, selectivity modifier, and to improve 10.2.1.2 FCC As a Maximum Diesel Engine
hydrothermal stability. Rare earth in zeolite concentra- Given the global trend toward dieselization, engineering and
tions typically vary from 0 to 16 wt %. catalyst companies have been placing increasing focus on
• Active alumina: Alumina is added to the catalyst to maximizing diesel yield from the FCC. Research for LCO
precrack high-molecular-weight molecules present in maximization has been focused on two primary approaches,
heavier portions of the feedstock. This precracking the first being the reduction of conversion together with
function enables further cracking by the zeolite present enhanced slurry destruction. These efforts are being spear-
in the catalyst, increasing the yields of gasoline and headed through efforts such as slurry recycling, increasing the
liquefied petroleum gas (LPG). The alumina technology catalyst-to-oil ratio, and reducing fresh catalyst intrinsic activ-
present today includes aluminas capable of absorbing ity through reduction of the zeolite-to-matrix ratio. Addition-
vanadium and encapsulating nickel, which are catalyst ally, catalyst manufacturers continue to maximize the intrinsic
poisons. Furthermore, catalyst manufacturers are now diffusion capabilities of the catalyst particle for maximal first-
capable of modifying the pore volumes and acidities of pass destruction of residue boiling molecules in the feedstock.
these aluminas, enabling specific cracking of difficult The second approach being taken by some manu-
feedstocks. Judicial use of alumina content is required facturers has been to experiment with nonstandard FCC
because most aluminas increase coke and dry gas yields. catalytic components in the catalyst. This has included
• Zeolite-to-matrix ratio: The relative composition of experimentation with basic materials as opposed to the
zeolite and alumina determines the yield selectivities standard acidic components. An observed benefit of this
observed by the refiner. novel approach is a reduction in the aromatic content of
In 1984, Mobil Oil launched a revolutionary new addi- the LCO, producing improved cetane number. The primary
tive, ZSM-5. ZSM-5 is a small-pore zeolite that selectively disadvantage of this approach is the low conversion resulting
cracks higher molecular weight olefinic molecules boiling in high slurry yields.
in the gasoline range. ZSM-5 has found wide application
in the FCC unit and is used primarily for maximizing 10.2.1.3 The FCC for Ultra-Heavy Feedstock
propylene yields, but it also has the capability of increasing Conversion
gasoline octane number. The exploitation of Alberta’s bitumen oil from the vast fields
of tar sands is currently at 1.5 million bbl/day. This produc-
10.2.1 Future Catalytic Developments tion rate is expected to increase to 3.5 million bbl/day by
The fluidized catalytic cracker is under continual pressure 2015 [4–6]. Most of the synthetic crude being produced in
to transform itself as global motor fuel markets evolve. There Alberta is coked followed by varying degrees of hydrotreating.
has rarely been a period in time in which there have not These synthetic oils currently occupy a minor position in
been substantial efforts being paid to further improving FCC North America’s FCC feed slates. The percentage of these
profitability. This continues to be true today. The following crudes reaching the FCC is expected to increase over the
are four areas that are currently under intense research for next few decades. Despite deep hydrotreating, these hydro-
improvement. carbon streams remain highly cyclic and therefore pose a
challenge to today’s catalysts. Substantial improvements in
10.2.1.1 FCC As a Platform for the stability, porosity, and accessibility of today’s “state-of-
Petrochemical Feedstocks the-art” residue catalysts will likely be required.
It is expected that by the middle of this century the world’s UOP is currently active in developing an “FCC-like”
remaining fossil fuel reserves will become much more pre- process, the Catalytic Crude Upgrading (CCU™) unit, which
cious given the growing global awareness of the effect of car- will be used to partially upgrade ultra-heavy crudes for
bon dioxide (CO2) on the environmental health of the planet viscosity reduction, thus eliminating the need for external
and the declining availability of easily recoverable reserves light hydrocarbon streams as diluents to meet pipeline
[3]. For this reason it is probable that the FCC will transform specifications. The CCU unit produces its own diluent while
itself steadily into a feed preparation unit for existing and maximizing the volume retention of crude barrels from
yet to be discovered chemical processes. The preeminence ground to pipeline. These crude oils are typically extremely
of today’s FCC unit as an engine for the production of motor high in vanadium and require a degree of vanadium toler-
fuels will likely diminish as the decades pass. ance well beyond the standard FCC catalytic technology
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Substantial resources are currently being directed toward of today. UOP and its partners are currently developing
increasing the selectivity of the FCC toward producing ultra-high vanadium-resistant catalysts.
petrochemical feedstock intermediates. The most obvious
example of this trend is continued emphasis on propylene 10.2.1.4 FCC Designed for Minimal
maximization in residue feedstocks. The major engineering Environmental Impact
companies in the FCC world continue to invest substantial The FCC, as with all chemical processes used today, is
resources to shift the yield selectivity toward propylene under increasing pressure to produce fuels and petro-
through measures such as reduction of hydrocarbon partial chemical intermediates with zero emissions, including
pressure, using multiple risers for higher severity, cracking CO2. Current technology [7,8] is able to control sulfur
naphtha as a feedstock directly into propylene, etc. Catalyst oxide (SOx) emissions in full combustion units with reduc-
and additive companies continue to focus efforts on low tions of 90–95 % common. SOx reductions in partial burn
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Chapter 10 n Advances in Catalysts for Refining Processes 225

perations are typically 50–70 %. Research continues on

o and b enzothiophene (BT) were examined in the H2 stream
many fronts to improve the SOx capture efficiency for par- with or without H2S (Table 10.1) [16]. Even with a small
tial burn operations. Deeper reductions currently require amount of H2S (0.1 vol % in H2), all thiophenes’ HDS was
the FCC operator to switch from partial to full burn opera- strongly retarded, and the reaction rate constants obtained
tion (if applicable), implementation of feed hydrotreating, were 15–20 % of the original. The reactions of diisobutyl-
or utilization of flue gas treatment technologies such as flue ene, 1-octene, and 1-hexene were examined in the H2 stream
gas scrubbers. FCC flue gas nitrogen oxide (NOx) emission with or without H2S (Figure 10.1) [16]. With H2S, the HG
control continues to be an area requiring further research. of diisobutylene is promoted whereas HG of 1-octene and
Typical reduction levels of 50–60 % are achieved with cur- 1-hexene is retarded. This finding shows that the isoolefin
rent additive technology [9]. Finally, there is an increasing HG active site is different from the HDS active site, and it
emphasis on particulate emissions reduction from the FCC may be possible to control the selectivity of CCG HDS.
unit. Fortunately for the FCC operator of today barrier filter To further clarify the difference between the HDS
technology exists to nearly eliminate particulate emissions active site and the isoolefin HG active site, the response of
from the FCC unit [10]. the catalyst activity to the well known promoting effects
of cobalt was studied using catalysts with varying cobalt
10.2.1.5 Conclusion content. The results are shown in Figures 10.2 and 10.3.
The FCC unit has proven to be one of the most flexible As is well known [17], thiophene HDS drastically increased
technologies within the oil refining industry for nearly 7 with increasing Co/(Co+Mo) ratio. On the other hand, with
decades. Although the challenges continue to mount, the increasing Co/(Co+Mo) ratio, it is noted that the HG of
equilibrium nature of the process lends itself readily to diisobutylene decreases a little and that of 1-octene largely
“online” experimentation, thereby enabling the aggressive decreases. The similar decreasing trend has been reported
refiner to maintain the “cutting edge” nature of the operation. regarding the activity for butene HG on unsupported
Continued research and development is essential for the cobalt-molybdenum sulfide catalyst, in which thiophene
FCC unit to maintain its central role within the modern HDS and successive butene HG were undertaken at 320°C
high-conversion refinery of today. and atmospheric pressure [18]. They have explained about
the phenomena that the addition of cobalt ions blocks
10.3 Catalyst Low-Sulfur Gasoline
Production
10.3.1 Introduction Table 10.1—Effects of H2S on Alkyl-(Benzo)-
CCG is produced from VGO or atmospheric residue by FCC thiophenes HDS [16]
units and it contains high levels of sulfur. Hydrodesulfur- H2S concentration in H2, vol%
ization (HDS) is usually applied for sulfur removal of the
petroleum fraction. However, CCG contains 20–40 vol % 0 0.1
olefins, therefore the present naphtha HDS process would Sulfur Compound HDS, %
reduce the octane value because of the hydrogenation (HG)
of olefins. Control of the HDS selectivity of the catalyst thiophene 86.0 27.0
requires that the HDS active site is different from the olefin 2-methylthiophene 63.8 10.9
HG active site. Several studies on molybdenum catalysts
3-methylthiophene 75.3 22.3
show that the HDS active site is different from the olefin
HG active site [11–13]. 2, 5-dimethylthiophene 45.3 12.0
This section focuses on the features of the selective CCG
2-ethylthiophene 47.2 10.7
HDS catalyst. The properties of CCG and the desulfurization
processes are presented in Chapter 7. benzothiophene 99.4 63.8
Reaction conditions: temperature 160 ˚C, pressure 1.3 MPa, H2 /feed ratio
10.3.2 Active Sites of the Catalyst 1.60 mol/mol, catalyst/feed 0.34 g of cat.min/mol sulfur compounds
To improve the HDS selectivity of CCG, it is necessary to concentration 2.83 × 10–4 mol/mol.
make clear the difference between the HDS active site and
the olefin HG active site. Thiophene and butene have been 35
used for the study of the HDS mechanism, and most of these diisobutylene
30
works have indicated that the HDS active site is different
Hydrogenation, %

1-octene
from the butene HG active site [11,13,14]. 25 1-hexene
The difference of the active sites was studied on
20
Co-Mo/γ-Al2O3 catalyst using the inhibiting effects of hydro-
gen sulfide (H2S). As is well known [15], H2S is adsorbed 15
on the HDS active site having coordinative unsaturation 10
and it competitively inhibits the other sulfur compounds’
5
access to the HDS active site. If olefin reactions are affected
by H2S as HDS is affected, then the structure of the olefin 0
0 0.2 0.4 0.6 0.8 1 1.2
HG active site is considered to be similar to that of the
H2 S concentration, %
HDS active site. If olefin reactions are not affected by
H2S, then the structure of the active site for olefin reac- Figure 10.1—Effects of H2S on olefin HG at a temperature of
tions may be different from that of the HDS active site. The 150°C, pressure of 1.3 MPa, H2 / feed 0.34 g of cat min/mol, feed
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effects of H2S on the HDS of thiophene, alkylthiophenes, toluene 80 mol %, and olefin 20 mol % [16].
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226 Petroleum Refining and Natural Gas Processing

Thiophene HDS Diisobutylene hydrogenation investigated by microreactor [19]. Thiophene HDS, diiso-
Diisobutylene hydrogenation, % 80
butylene HG, and 1-octene HG were studied at 150°C and
1.3 MPa to measure the original activity. Thiophene (2.83 ×
Thiophene HDS, %

60 10−4 mol/mol)/pyridine (0.01 mol/mol)/toluene, diisobutylene

(0.25 mol/mol)/toluene, and 1-octene (0.25 mol/mol)/toluene
40 were passed into the reactor and the inhibition by pyridine
* spike was studied. The temperature was then increased to
20 300°C to strip the pyridine and then the temperature was
decreased back to 150°C to measure the remaining effects of
* pyridine. After pyridine was desorbed at 300°C, HDS activity
0
0 0.1 0.2 0.3 0.4 0.5 had almost recovered to the initial level. However, the activity
Co/(Co+Mo), mol/mol for diisobutylene HG still remained much lower than the ini-
tial activity. The activity for 1-octene HG recovered to half of
Figure 10.2—Effects of cobalt on HDS and isoolefin HG MoO3
15.0 mass % (*7.5 mass %), temperature 175°C, pressure of
the initial activity. The remaining effect of the pyridine spike
1.3 MPa, H2 / feed 0.34 g of cat min/mol, feed thiophene 2.83 × on isoolefin HG was stronger than that on n-olefin HG. These
10–4 mol/mol, toluene 80 mol %, and olefin 20 mol % [16]. observations strongly support the idea that three different
types of active sites are present on the catalyst.
Thiophene HDS 1-octene hydrogenation From these results, one can speculate on the following
80
three types of active sites:
1-octene hydrogenation, %
Thiophene HDS, %

1. HDS active site: This site is inhibited by H2S and pro-

60 moted by cobalt. n-Olefin and isoolefin can approach.
2. n-Olefin HG active site: This site is inhibited by H2S
40 * and cobalt. This site has some similarity with the HDS
active site.
20 3. Isoolefin HG active site: This site is promoted by H2S
* and is slightly inhibited by cobalt. This site strongly
0 interacts with isoolefin, resulting in the formation of
0 0.1 0.2 0.3 0.4 0.5 an oligomer. This site is totally different from the HDS
Co/(Co+Mo), mol/mol and n-olefin active sites.
Figure 10.3—Effects of cobalt on HDS and n-olefin HGMoO3 These phenomena suggest the possibility of a selective
15.0 mass % (*7.5 mass %), temperature 190°C, pressure 1.3 CCG HDS in which the HDS reaction performs with mini-
MPa, H2 / feed 0.34 g of cat min/mol, feed thiophene 2.83 × 10−4 mizing olefin HG because most of the olefins contained in
mol/mol, toluene 80 mol %, and olefin 20 mol % [16]. CCG are isoolefins.

the coordinatively unsaturated molybdenum sites on the 10.3.3 HDS Selectivity Improvement
edges of molybdenum disulfide (MoS2) and decreases the Cobalt addition test shows that the proper amount of cobalt
HG activity. If cobalt blocks the unsaturated molybdenum loaded on γ-Al2O3 gives good selectivity for CCG HDS by
sites, the small effects of cobalt on isoolefin HG suggest that lowering n-olefin HG activity. Cobalt distribution also
isoolefin HG proceeds on the unsaturated molybdenum contributes to the selectivity improvement. Highly dispersed
sites not blocked by cobalt. In the case of catalyst having half cobalt catalyst was prepared with CyDTA-Co(trans-1,2-di-
metal content (*marked), thiophene percentage conversion aminocyclohexane-N,N,N’,N’-tetraacetic acid-cobalt) [20].
largely decreases; however, percentage of olefin HG slightly Thiophene HDS and 1-octene HG reaction were examined
decreases. The mass percentage (7.5 mass %) of molybdenum and the activities were compared with conventional Co-Mo/
trioxide (MoO3) is too small to cover the whole surface of the γ-Al2O3 catalyst. CyDTA-Co showed higher HDS activity and
Al2O3. Uncovered Al2O3 surface may enhance olefin HG. lower 1-octene HG activity than the conventional catalyst.
These results also indicate that HDS and olefin HG proceed It was found that isoolefins were oligomerized on
at the different active sites. the isoolefin HG active site [21]. Oligomer may finally be
The studies of the effects of H2S and cobalt are summa- irreversibly deposited on the active site as a coke. If it is
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
rized in Table 10.2. The effects of pyridine modification on the possible the coke selectively deactivates that isoolefin HG
catalyst activity and selectivity of Co-Mo/γ-Al2O3 catalyst were active site; then this leads to selective CCG HDS.
Three different combinations of the pretreatments were
performed on the fresh catalyst. They were sulfiding + aging,
Table 10.2—Effects of H2S and Co on HDS sulfiding + aging + coking, and coking + sulfiding + aging.
and HG [16] The coking pretreatment was done using a mixture of cyclo-
H2S Co hexene + 1-methylnaphthalene. The result of CCG HDS is
shown in Figure 10.4 [21]. The catalyst with sulfiding + aging
HDS inhibition promotion gives a higher total HDS percentage than the catalyst with
coking. Concerning the HDS selectivity, the catalyst with
hydro. sulfiding + aging + coking shows higher selectivity than the
promotion no effect
catalyst without coking. However, the catalyst with coking +
sulfiding + aging shows the same selectivity as the catalyst
hydro. inhibition inhibition without coking. These results show that coking pretreatment
should be done after sulfiding to improve HDS selectivity.
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Chapter 10 n Advances in Catalysts for Refining Processes 227

25 25
Fresh cat,: sulfiding+aging sulfiding

1-octene hydrogenation, %
Fresh cat.: sulfiding+aging+coking sulfiding+aging
20
Olefin hydrogenation, %
20
Fresh cat.: coking+sulfiding+aging
sulfiding+aging+coking
Spent cat.: sulfiding
15 15
Spent cat.: regeneration
+sulfiding+aging
10
10

5
5

0
0 0 20 40 60 80
0 20 40 60 80
Thiophene HDS, %
Total HDS, %
Figure 10.6—Effects of coking on HDS selectivity in the
Figure 10.4—Effects of coking pretreatment on HDS selectivity presence of n-olefin at a temperature of 190°C, pressure of
at a temperature of 300°C, pressure of 0.4 MPa, H 2 / feed 1.3 MPa, H2 / feed of 1.6 mol/mol, feed thiophene of 2.83 × 10−4
of 85 NL/L, and feed CCG (sulfur 157 ppm [mass] and olefin mol/mol, toluene of 80 mol %, and olefin of 20 mol % [21].
36.6 vol %) [21].
HG activity. Because most olefins in CCG are isoolefin, it is
The effects of coke were further examined using a refin-
considered that CCG HDS selectivity is improved by coking
ery spent catalyst, which was used in the diesel fuel HDS
pretreatment.
process for 1 year. This catalyst, having 8.8 mass % deposited
coke, was supplied for CCG HDS activity test. This spent
10.3.4 CCG HDS Commercial Catalysts
catalyst also shows high HDS selectivity. However, this high
A Co(Ni)-Mo/-Al2O3 catalyst is used in the actual CCG HDS
selectivity was lost by a regeneration procedure. This result
process. Several modifications are made to improve the
suggests that coke deposit improves the HDS selectivity.
selectivity. It is supposed that alkaline metals and alkaline
Thiophene HDS was performed over the catalyst with
earth elements reduce olefin HG activity [22]. Coking is also
or without aging and coking pretreatment in the presence
effective as a pretreatment of the catalyst for selectivity
of diisobutylene and 1-octene [21]. Thiophene HDS is little
improvement [13]. The patent shows that SCANfining
reduced by the aging pretreatment but is much reduced by
developed by ExxonMobil and Akzo Nobel uses the combi-
the coking pretreatment. The diisobutylene HG percentage
nation of two catalysts (Table 10.3) [23]. RT-225 is a main
is plotted against thiophene HDS in Figure 10.5. Little
selective CCG HDS catalyst. KF-742 is a conventional HDS
difference is observed between the selectivity of the catalyst
catalyst and is sometimes used together with RT-225. The
with or without aging. However, it is noted that diisobutyl-
information on the catalysis of other processes is scarce,
ene HG of the catalyst with coking is much lower than that
but similar catalysts may be used.
of catalysts without coking.
The 1-octene HG percentage is plotted against thiophene
10.4 Recent Advances in Deep HDS
HDS in Figure 10.6 [21]. The 1-octene HG of the catalyst with
Catalysts
coking is much higher than that of catalysts without coking.
10.4.1 Catalysts for Deep HDS of Diesel Fuel
The effects of coking pretreatment on the three different
The desulfurization technology for diesel fuel has advanced
types of active sites are as follows: isoolefin HG active site
rapidly as oil companies, catalyst manufacturers, engineering
> thiophene HDS active site > n-olefin HG active site. This

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
companies, universities, and public research institutes all
order also suggests that the coking pretreatment effectively
competed with one another to develop catalysts or processes
reduces isoolefin HG activity but hardly reduces n-olefin
when the regulation on sulfur contents in diesel oil was
changed to 500 ppm starting in 1997 as a response to the
25
report by the Central Council for Environmental Pollution
Diisobutylene hydrogenation, %

sulfiding
Control in 1989 in Japan, requiring oil companies to newly
20 sulfiding+aging
introduce desulfurization systems. This has resulted in a
sulfiding+aging+coking leap of science and know-how on deep HDS and deep HDS
15 catalysts for ultralow sulfur diesel (ULSD) production [24].

10
Table 10.3—Catalysts for SCANfining [23]
5
RT-225 KF-742

0 Support Alumina Alumina

0 20 40 60 80
Av. pore dia. 87 72
Thiophene HDS, %
MoO3, mass % 4.2 15
Figure 10.5—Effects of coking on HDS selectivity in the
presence of isoolefin at a temperature of 175°C, pressure of CoO, mass % 1.2 4
1.3 MPa, H2 / feed of 1.6 mol/mol, feed thiophene of 2.83 × 10−4
HDS activity <0.5 1
mol/mol, toluene of 80 mol %, and olefin of 20 mol % [21].
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228 Petroleum Refining and Natural Gas Processing

The major components of sulfur compounds in diesel mind that HDS of such refractory compounds should be thor-
fuel are alkyl derivatives of BT and dibenzothiophene oughly performed in deep HDS. Because this 4,6-DMDBT
(DBTs). HDS is a reaction to remove sulfur from these com- alone is contained as sulfur content of 100 ppmw or higher
pounds in the form of H2S while maintaining the carbon in feed oil, it needs to be reduced to one tenth that of the feed
skeleton structures. Furthermore, denitrogenation of organic oil. Table 10.4 presents the relative desulfurization activi-
nitrogen compounds and HG of aromatic compounds also ties of alkyl-BTs examined by Houalla et al. [26]. It becomes
proceed in concurrence with the desulfurization in diesel oil. more difficult to desulfurize when a methyl group is attached
Because the organic nitrogen compounds in diesel fuel are to position 4 or 6 adjacent to the sulfur atom. For example,
inhibitors of HDS, denitrogenation is a favorable reaction in 4,6-DMDBT has one tenth less reactivity than DBT. It is con-
a similar fashion to desulfurization. Meanwhile, condensed sidered that this is caused by steric hindrances for adsorption
polycyclic aromatic compounds in diesel fuel are a source of of the sulfur atom to the active site of the catalyst because
particulate matter (PM) when the diesel fuel is combusted; the alkyl substituent is located near the sulfur atom [27]. It
thus, their HG is also a favorable reaction. However, there is therefore expected that the reactivity can be improved dra-
is a problem of increased hydrogen consumption in these matically if it is possible to remove or mitigate the inhibition
reactions. It is therefore necessary to conduct deep desulfur- by this methyl group before the C–S bond cleavage.
ization and optimize these reactions to suit the purpose of Desulfurization of 4,6-DMDBTs can take a direct route
environmental and economic imperatives. in which the sulfur atom is directly hydrogenated and then
This section provides an outline of catalyst technology desulfurized, a HG route in which it is desulfurized after
regarding the problems to be solved for ultra-deep HDS the aromatic ring is hydrogenated, or an isomerization
and methods to address ultralow sulfur-free diesel fuel with route in which the methyl group is transferred by isom-
sulfur contents of 10 ppm or lower. erization as shown in Figure 10.8. Mochida et al. reported
that the HG reaction of the aromatic ring became subject
10.4.2 HDS Reactions of Gas Oil to restriction by thermodynamic equilibrium under high
Figure 10.7 shows the results of investigating the sulfur
compound distribution in the straight-run diesel fuel
(sulfur content 1.4 wt %) and treated gas oil after HDS Table 10.4—Relative Activity of
(sulfur content 380.35 ppmw) using gas chromatography Alkyl-DBTs [25]
with atomic emission detector (GC-AED) [25]. It is evident
Relative HDS
that various sulfur compounds including BTs and DBTs
Compound Activity
are contained in the raw diesel fuel. On the other hand,
the product oil after the HDS at 380 ppmw has lost most 2,8-DMDBT 2.6
of the peaks observed for the raw diesel oil with the only
remaining peak in the high boiling-point region. In product
oil that is more deeply desulfurized at 35 ppmw, it is shown
that only 4,6-dimethyldibenzothiophene (4,6-DMDBT) and 3,7-DMDBT 1.5
DBTs with large alkyl group sidechains remain.
In ultra-deep HDS, the concentration of sulfur in diesel
oil needs to be reduced to one thousandth. Therefore, nearly
all sulfur compounds must be removed from diesel oil by DBT 1.0
HDS. As seen from the chromatogram for product oil (sulfur
content 380.35 ppmw) shown in Figure 10.7, the residual sul-
fur compounds include mainly refractory sulfur compounds
such as 4,6-DMDBT. Thus, it is naturally necessary to keep in 4-MDBT 0.16

4,6-DMDBT 0.1

Figure 10.7—GC-AED chromatogram of raw and hydrotreated --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

gas oil [25]. Figure 10.8—HDS reaction pathways of 4,6-DMDBT [28].

AST-MNL58-11-0801-010.indd 228 3/12/13 2:15 PM

Chapter 10 n Advances in Catalysts for Refining Processes 229

temperatures in the HG route for alkyl-DBT, and that 10.4.3.1 Control of CoMoS Phase for Higher
HG of DBT for instance is not favored at 330°C or higher Activity
regarding thermodynamic equilibrium, with little forma- The CoMo alumina catalyst popularly used in HDS requires
tion of hydrogenated compounds at temperatures as high presulfiding to be activated before reaction. Before deep
as 425°C. They also report that the reaction is not favored desulfurization of the 500-ppm level was implemented, it
for 4,6-DMDBT at 260°C or higher and that there is little was assumed that Mo and Co were individually sulfided
formation of hydrogenated compounds at 380°C [28]. In and existed as MoS2 and Co9S8 on alumina carrier. How-
ultra-deep HDS, it is necessary to improve the primary ever, recent advancements in various analytical techniques
HDS activity in addition to solving the issue of how these revealed a unique structure called the CoMoS phase in which
reaction paths shall be realized on the catalyst and the molybdenum and cobalt are bonded, which functions as the
issue to mitigate the steric hindrances by methyl groups. active site for HDS. As shown in Figure 10.10 [31], it has a
As mentioned above, the improvement of catalysts and unique cluster structure with the fundamental skeleton of
processes in sulfur-free level is conducted giving attention the MoS2 structure and cobalt coordinated on the cluster’s
to the desulfurization mechanism. edge. In general, the two important points in improving
Furthermore, it is generally considered that the con- the catalyst activity are increasing the number of active
centrations of sulfur and nitrogen in the feed oil affect the sites and improving the performance of the active sites. It
desulfurization reactivity. Figure 10.9 shows the relation- thus means that the number of CoMoS phases should be
ship between the correction factor calculated from sulfur increased or its performance should be improved to prog-
and nitrogen contents in feed oil by the following formula ress to better HDS activity. To conduct the former, the
and required desulfurization temperature. It is supposed possible methods include an increase in the molybdenum
that the ratio between sulfur content and nitrogen content and cobalt content; an increase in the surface area of alumina,
in feed oil can be used to grasp the reactivity of the feed which is the carrier for these active metals; and effective
oil [29]. formation of the highly diffused CoMoS phase.
Meanwhile, to improve the performance per active
Correction factor = (nitrogen content in feed oil/sulfur site, it is considered that a method to adjust the interaction
content in feed oil)2.8 × (sulfur content in feed oil)2.2 (10.1) with the carrier may be effective. It has been recently found
that the activity becomes higher as the interaction between
This indicates that the nitrogen compounds in feed oil the alumina carrier and the CoMoS phase is lower [32].
work as reaction inhibitors in deep HDS; thus, denitrogena- It is known that some chelating agents are effective in form-
tion of these nitrogen compounds also becomes important ing this type of CoMoS phase, and there are study reports
in ultra-deep HDS. claiming that P, B, and so forth conventionally known to
have activity improvement effects somewhat influence the
10.4.3 Trend of Catalyst Development for formation of the CoMoS structure. Therefore, several inter-
Sulfur-Free Diesel Oil esting preparation methods are being contrived.
As described in Section 10.4.2, the catalyst needs to be
highly active and extend the lifespan by decreasing the reac- 10.4.3.2 Enhancement of Methyl Group
tion temperature so that the refractory sulfur compounds Migration
such as 4,6-DMDBT can be selectively desulfurized to Acid sites are necessary for migration of alkyl groups on
achieve a sulfur-free level. There are several catalyst design alkyl aromatics, and various Lewis acids are known to work
concepts proposed for these improvements [30]. It is also on this reaction. Acid sites of some zeolite are also known
necessary to develop a catalyst that is resistant to inhibition to be effective. Thus, examinations are being made on car-
by H2S, nitrogen compounds, or ammonia. riers combining these Lewis acids or zeolite with alumina
carrier or using zeolite alone as the carrier. However, strong

Figure 10.9—Correlation between nitrogen and sulfur collection

factor and achievable reaction temperature for 50 ppm Figure 10.10—Surface structure of sulfided CoMo/Al2O3 catalyst
sulfur [29].
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- proposed by Topsøe and others [31].
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230 Petroleum Refining and Natural Gas Processing

acid sites may lead to unfavorable decomposition reactions catalysts are not limited to those developed for sulfur-free
(reduction of liquid yield) or coke formation reactions diesel oil but include catalysts for 50-ppm sulfur oil. It
(deactivation of catalyst) in addition to the migration of the is also necessary to select by sufficiently considering the
methyl group, possibly leading to rapid activity deteriora- catalyst performance because each has different charac-
tion during the initial stages of operation (during SOR). If teristics (drawbacks and advantages). However, catalyst
excessive decomposition or coke formation can be mini- manufacturers continue to devote their efforts in research
mized by adding an appropriate acid property, then it may and development. It is expected that better catalysts will be
be possible to develop a catalyst that improves catalyst life manufactured in the near future.
and promotes methyl group migration.
10.5 Advances of Catalyst Technology in
10.4.3.3 Enhancement of HG Activity VGO Hydrotreating
The HG reaction of an aromatic ring to mitigate steric 10.5.1 Advances in Guard-Bed Catalyst
hindrances by methyl groups is expected to be promoted The guard-bed catalyst loading in the reactor top layer is very
by catalyst metals with good HG activities. Although NiMo, important to protect the main-bed catalyst against fouling
NiW, or precious metal catalysts are normally effective in and catalyst poisons, which can severely affect the expected
the HG of condensed polyaromatics, it is known that these activity and cycle length. The reactor pressure buildup takes
catalysts with good HG activities are prone to inhibition of place by the accumulation of deposits in the catalyst bed. To
reaction by H2S, ammonia, and so forth under the reaction remove the effect of deposition on pressure drop buildup and
conditions. Furthermore, there are negative effects to unnec- keep good liquid distribution, a grading of catalyst shapes,
essarily increase the hydrogen consumption because HG sizes, and activities is crucial. The foulants that cause the
of aromatics that are not related to desulfurization is also problem in hydrotreating reactors come from several differ-
facilitated when these catalysts with good HG activities are ent sources, including the following [35–37]:
used. Therefore, some combination of CoMo and NiMo or • Particulates of widely varying sizes and compositions;
NiW catalysts has been proposed in the sulfur-free condition. • Gum formation due to reactive molecules such as olefins
and oxygenates; and
10.4.3.4 New Developments in Catalyst • Inorganic contaminants, such as iron, nickel, vanadium,
Support Materials arsenic, and silicon.
In general, industrial catalysts for HDS comprise Mo or W and The particulates include coke fines, iron sulfide, some-
Co or Ni on alumina carrier. There are investigation reports times FCC catalyst fines, and so on and are prospectively
indicating that catalysts using titania as the catalyst carrier removed by grading the catalysts using optimized shape/size
show better desulfurization activity per unit surface area [33]. and reactivity for the targeted contaminants. Gum formation
Especially regarding HDS of refractory sulfur compound 4,6- is a problem commonly seen in commercial hydrotreating
DMDBT, some report that it functions better than alumina reactors, where contaminants of olefins, di-olefins, and
carrier catalysts. However, because of the disadvantages of oxygenates present in the VGO feed react with the cata-
titania, including less thermal stability and small specific lyst very rapidly and exothermically, creating problems of
surface area (~50–60m2/g), there have been few actual cases reactor fouling, maldistribution, and thermal hot spots.
of industrial manufacturing. The technology to increase the The third type of fouling occurs when inorganic elements

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
surface area and precisely control the pore size distribution to such as nickel, vanadium, arsenic, and silicon enter the
solve the disadvantages of titania carrier was recently devel- hydrotreater. These metals are poisons to the hydrotreating
oped [34]. It is an unconventional and interesting catalyst. catalysts and cause severe deactivation. Hence, poison
removal before the main-bed catalysts needs to be properly
10.4.3.5 Commercial Catalysts facilitated. The removal of reactive molecules and inorganic
The catalysts of catalyst manufacturers and licensers that poisons is achieved by a gradual change in the catalyst
have been developed and industrialized along one of the activity and by applying catalysts with trapping capacity
concepts explained above are listed in Table 10.5. These for various metals. A common industrial practice for con-
taminant control is suitably highlighted by the superior
performance achieved by the consecutive use of
Table 10.5—Commercial Catalysts for Deep • Ketjenfine KG-55 of a specific pentaring alumina
HDS (outer diameter [OD] 19 mm, void fraction 62 %)
Catalyst Manufacturer • Followed by Ketjenfine KF 542-9R/-5R of moderate
or Licenser Catalyst Name activity of nickel-cobalt-molybdenum Raschig ring cat-
Albemarle KF-772 KF-757H KF-848 Nebula alysts (9.0/3.5mm and 6.0/2.8mm in OD/inner diameter
[ID], void fraction 50 %) for elimination of olefins and
ART SmART (CDX, CDY) oxygenates to prevent gum and coke formation
Criterion Catalyst DC-2318 DC-2531 DN-3330 • Then a nickel-molybdenum alumina Demet catalyst
(OD 3–5 mm, void fraction 45 %) for removal of metal
Halder Topsoe A/S TK-573 TK-574 poisons.
IEP Axens HR-626 HR-526 HR-568 HR-548 The higher activity and smaller shaped nickel-
molybdenum catalysts at the last Demet position are able to
Cosmo Oil Co. C-605A
completely remove nickel and vanadium contaminants while
JGC C&C CDS-LX6 maintaining good liquid flow through the catalyst bed [35,36].
The latest development includes the trapping capability of mul-
Nippon Oil Co. NHS-204
tiple contaminants such as iron, arsenic, and silicon as well as
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Chapter 10 n Advances in Catalysts for Refining Processes 231

nickel and vanadium. The iron deposition normally originates of the FCC unit, product selectivity, and product quality.
from corrosion scales, which are of various sizes (0.1–10 mm). FCC-PT units span a wide range of processing conditions
However, more difficult to deal with are the organic iron mol- and objectives. Low-pressure units (i.e., 40–60 bar hydro-
ecules often present in the heavier and high total acid nitrogen gen partial pressure) primarily address HDS to reduce SOx
(TAN) feeds. These organic iron molecules are very reactive, emission from the FCC unit and sulfur content in the FCC
forming iron sulfide. Iron sulfide in turn accelerates coke for- gasoline. High-pressure units (i.e., 70–100 bar hydrogen
mation, through the dehydrogenation reaction at the surface pressure) are able to significantly reduce nitrogen, aromat-
of the catalysts, and the agglomerated catalysts bound with ics, and continuous catalytic regeneration (CCR) content
iron sulfide and coke cause serious fouling problems. One of of the FCC feed in addition to substantial sulfur reduction.
the significant developments for iron trapping capability is Such high-pressure FCC-PT “sweetening” enables produc-
Ketjenfine KG-1 [37]. This spherical catalyst (5 mm in diam- tion of much more light fuels of better quality from heavy
eter) is used for the removal of iron scale and organic iron and hydrogen-deficient feeds. The innovation for VGO
molecules. The catalyst is designed to trap the iron inside of hydrotreating catalytic technology has been remarkable
the pore structure, ensuring maximal iron trapping efficiency in the last decade, often on a par with those observed in
and preventing the accumulation of coke on the outer surface the distillate hydrotreating catalytic technology. Cobalt-
of the catalyst particles. Another new development in guard- molybdenum on alumina catalysts has traditionally been used
bed technology is new catalysts that specifically target arsenic for the HDS objective in low-pressure VGO hydrotreaters.
and silicon removal. Arsenic is present from several hundreds Nickel-molybdenum catalysts have been developed and used
to thousands of parts per billion in bitumen and some other for the high-pressure applications to improve the HG activity
heavy crudes. Arsenic is a very strong poison for the down- for more aromatic saturation as well as nitrogen and CCR
stream hydrotreating catalysts; for example, 50 % of catalytic removal. Historically, either CoMo or NiMo catalysts have
activity can be lost with only 0.1 wt % of arsenic present on the been made with alumina support materials of high surface
catalyst. Silicon is the contaminant from the crudes and more area and acidity. The precursors of NiMo or CoMo metals
significantly from the hydroprocessing of coker products. In are then impregnated onto the alumina, dried, and calcined
the coking process, silicon-containing antifoaming agents are to make the final catalysts. The key technology here is to
used and the decomposed silicon-containing molecules are produce a high activity catalyst by high dispersion of the
present in the derived coker products. The poisoning effect of active metal species of CoMoS or NiMoS or both onto the
silicon is such that 50 % activity loss can be seen with 12–15 wt support materials. The improvement and optimization of
% of silicon deposition on the catalyst. Consequently, removal support acidity, pore structure, and manufacturing technol-
of arsenic and silicon contaminants are of strong interest for ogies have been the major focus in developing high-activity
optimizing required activity and cycle length as well as nickel catalyst via high dispersion of the active species. Such
and vanadium removal. The latest significant catalytic tech- catalysts have much more interaction between the support
nology for arsenic, silicon, nickel, and vanadium trapping is and metal species and are referred to as Type I catalysts, as
Ketjenfine KF 647 and KG 6 [36]. The former catalyst focuses tabulated in Table 10.7.
more on silicon trapping and the latter on arsenic trapping, The classic approach for catalyst development had
in addition to providing the trapping capacity for nickel and been the improvement of metal species dispersion for the
vanadium contaminants. Thus, this kind of multifunctional increased active sites. However, Albemarle found in the
Demet catalysts plays a very important role for “contaminant late 1990s that the metals-support interaction was even
management” in the guard-bed reactor and achieving the more important for improving intrinsic activity. Albemarle
expected activity and cycle length of the unit. The latest Demet and Nippon Ketjen commercialized a new, superior CoMo
development for common commercial practices is tabulated catalyst called Ketjenfine 757 by applying a proprietary
in Table 10.6. and patented production technology in 1998. This catalyst
achieved very deep HDS in distillate and VGO hydrotreating
10.5.2 Advances in Main-Bed Hydrotreating applications [38–48]. Ketjenfine 757 was developed for the
Catalyst first time using a new catalyst design concept (i.e., highly
10.5.2.1 Catalyst Technology in FCC-PT dispersed active sites of an optimized metals-support inter-
The hydrotreating of FCC feedstock, to produce a sweetened action to improve the intrinsic activities), thereby providing
feed to the FCC unit, can greatly improve the performance an overall higher catalytic activity. Albemarle named such

Table 10.6—Albemarle’s Guard-Bed Technology for Multiple Contaminant Control [35–37]

KF 647 KF 648 KF 841 KG 6

Function Hydrogenation Demet Hydrogenation Demet Hydrogenation Demet Arsenic trap

Removes Ni, V, As, Si Ni, V Ni, V Ni, V, As

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Composition NiMo NiMo NiMo NiMo

Shape Quadralobe Quadralobe Quadralobe/cylinder Quadralobe

Diameter (mm) 1.3/2.6 1.3/2.6 1.3/2.1/2.6 2.6

Av. length (mm) 3.5/5.0 3.5/5.0 3.5/5.0 5.0

Sock density 510 510 625–695 530

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232 Petroleum Refining and Natural Gas Processing

Table 10.7—Albemarle’s Type I and Type II Catalyst activities in FCC-PT service

Latest Catalytic Technologies [38,39]
Composition/ 220
Product Size/Shape Type Characteristics HDS
200
KF 752 1.5E, 2E, 3Q CoMo Type I Moderate HDS HDN

Relative Volume Activities

activity catalyst 180 HDA
KF 756 1.5E, 2E, 3Q CoMo Type I Higher HDS Type I
catalyst 160

KF 757 1.5E, 2E, 3Q CoMo Type II High HDS Type II 140

STARS catalyst

KF 767 1.5E, 2E, 3Q CoMo Type II Higher HDS Type II 120

STARS catalyst
100
KF 770 1.5E, 2E, 3Q CoMo Type II Much Higher HDS
STARS Type II catalyst 80
KF 841 KF 901 KF 857 KF 905 KF 757
KF 901 1.5E, 2Q NiCoMo Type I Moderate HDS and
HDN Type I catalyst Conventional STARSTM

KF 905 1.5E, 2Q NiCoMo Type II Higher HDS and Figure 10.12—Volumetric activities in FCC-PT VGO service
STARS HDN Type II catalyst [38,39].

KF 841 1.3Q, 3Q NiMo Type I Moderate HDN

activity HDS conditions as compared with the classic Type I tech-
nology. Ketjenfine 848 is a high-activity NiMo catalyst of
KF 846 1.3Q, 3Q NiMo Type I High HDN activity
catalyst Type II technology that is available.
The Type II catalytic development was also accompa-
KF 848 1.3Q, 2Q NiMo Type II High HDN Type II nied by optimization work in the catalyst activation and
STARS catalyst its required application. The best optimized liquid sulfid-
KF 857 1.3Q, 2Q NiMo Type II Higher HDN Type II ing procedure and conditions were identified to maximize
STARS catalyst the intrinsic activity of the Type II catalytic activity sites
[41]. To enable refinery gas-phase sulfiding in certain
KF 860 1.3Q, 2Q NiMo Type II Higher HDN Type II
units, a specific liquid treatment of PROTECTTM is also
STARS of high stability
applicable to Type II STARS TM catalytic technology for
HDN = hydrodenitrification. catalyst activation/startups that cannot use a liquid-phase
activation procedure [41]. The rejuvenation technology
new catalytic active sites as Super Type-II Active Reaction called REACTTM was also developed to allow refiners the
Sites (STARSTM) [38,39]. The highly dispersed Type II sites of opportunity for multiple use of a given Type II catalyst in
optimized support-metals interaction in STARS TM technology which activity recovery of more than 90 % can be routinely
can achieve at least 30 % higher activity than the classic achieved [41]. Thus, the catalytic development in VGO
Type I catalysts. As shown in Figure 10.11, the Type II cata- hydrotreating has been principally advanced and improved
lyst shows a highly dispersed single-layer MoS2 of curvature through the new concept of optimizing metals-support
structure. The reaction turnover frequency at Type II sites interaction under a highly dispersed state and the application
was found to be significantly increased, showing an activity technologies of optimal sulfiding and reactivation for multiple
benefit of 60 % or even higher (Figure 10.12) at the deeper use of a given catalyst. The Type II STARS technology is
one of the greatest achievements in the hydrotreating cata-
lytic technology developments in the last several decades.
The technology has provided the step-out performance
increase required by the market via a new catalytic concept
and helps the refineries achieve the ultralow sulfur regulation
in gasoline and diesel products.
There are several other catalytic advances published
concerning catalyst characteristics [49–54]. The University
of Aarhus and Haldor Topsøe succeeded in obtaining the
atomic scale of Co-Mo-S structure present in the hydrotreat-
ing catalyst by means of scanning tunneling microscopy
(STM) [49]. They clarified that the presence of the cobalt
promoter atom causes the MoS2 nanocluster shape to change
from a triangular to a hexagonally truncated form. This mor-
phological transformation drives the preference of the cobalt
atom to be presented at the sulfur edge of MoS2 and changes
Figure 10.11—Transmission electron microscopy micrographs the electronic environment of the neighboring sulfur atoms
of conventional and STARS catalysts.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
for improved HDS activity. Haldor Topsøe claimed that the
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Chapter 10 n Advances in Catalysts for Refining Processes 233

new BRIM active site of metallic character is created on the

50 years development in activity
top of MoS2 slabs close to the edge and plays an important
role for prehydrogenation for the succeeding HDS reaction.
They mentioned that the optimal balance of BRIM sites 1200
together with Type I and Type II sites is the key technology NEBULA
for improved catalytic activity and subsequently developed 1000

HDS activity
several new BRIM catalysts on the market [50,51]. Criterion
published that high dispersion of Type II catalytic active sites 800
of easier sulfidability is crucial for activity improvement
600
[52]. They claim that highly dispersed Type II sites of smaller STARS
slab size and less stacking structure can be made by a spe- 400
cific catalyst preparation technique, and it can then enable Traditional catalysts
a 100 % sulfidable MoS2 structure of resultant high activity. 200
They also suggested that the optimal balance of Type I and
Type II can be important for stability and longer cycle length 0
1950 1960 1970 1980 1990 2000 2010
as well as the SOR activity [53]. Thus, an in-depth under-
Year
standing of the active site structures and their functionalities
has progressed, thereby leveraging the extensive catalytic
Figure 10.13—Catalytic activity of conventional, STARS, and
activity improvement seen in the last decade. Nebula technologies.

10.5.2.2 Catalyst Technology in a

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Hydrocracking Pretreater R-1 hydrocracking pretreat activity
Hydrocracking (HC) is another VGO process to produce 2000 psig, 5000 SCF/B
naphtha and diesel fractions. Because the nitrogen in the
feed causes substantial inhibition to the acid sites of zeolitic KF 848
1000
or silica-alumina catalysts or both in the HC reactor, nitro-
NEBULA
gen removal is required in a HC pretreater (HC-PT). Thus,
a higher hydrodenitrification (HDN) activity HC-PT cata- 2.4 LHSV
Product nitrogen (wppm)

lyst is able to improve the performance of the HC process 100

2.4 LHSV 3.2 LHSV
through allowing more feed barrels or difficult feedstocks
or both of lower cost to be processed. KF 848 was the first
STARS TM Type II NiMo catalyst of improved HDN activity 10
for the HC-PT service and achieves 30–50 % higher HDN
relative to the conventional Type I catalyst used previously
in the HC-PT application. The latest development in this 1
STARS catalyst market has brought even higher HDN activity Nitrogen ≤1 wppm 3.2 LHSV
catalysts than described above [45,46]. SOR T ≥ 680 ºF for KF 846
Albemarle, Nippon Ketjen, and ExxonMobil jointly devel- 0.5
oped the unprecedented high-activity catalyst NebulaTM in 560 580 600 620 640 660 680
2001 [43,44,55,56]. The NebulaTM breakthrough technology Temperature (ºF)
reaches previously unattainable levels of desulfurization,
denitrogenation, and aromatic saturation in kerosene, distil- Figure 10.14—HDN activity in HC-PT with KF 848 and Nebula.
late, and VGO applications. The NebulaTM concept represents,
in the author’s opinion, the greatest single step forward since are operated in MHC mode to produce more distillate at a
the beginning of hydroprocessing catalyst development in higher temperature while providing a good FCC feedstock.
the 1950s, as amply illustrated in Figure 10.13. NebulaTM The catalysts for MHC operation need CoMo or NiMo or
also shows great benefits in the demanding commercial both on alumina-, amorphous silica-alumina-, or zeolitic-
applications of HC-PT as shown in Figure 10.14. containing support for the enhanced cracking activity of
reasonable stability [41,57]. Table 10.8 shows Albemarle’s
10.5.2.3 Catalyst Technology in Mild latest MHC catalyst portfolio. These catalysts have demon-
Hydrocracking strated the expected HDS, HDN, conversion to distillate,
Mild hydrocracking (MHC) is a hydroprocessing application and satisfactory stability in various commercial applications.
for partially converting VGO to primarily middle distillate The latest commercial practice has started to apply Type II
products while achieving the needed HDS activity. MHC is catalytic technology to the MHC application for better
typically a low to medium conversion process (ca. <50 %), performance and stability for longer cycle length.
usually being operated at relatively moderate pressure
conditions of approximately 40–70 bar hydrogen partial 10.6 Catalysts for Bottom-of-the-
pressure, typically with a single reactor. The product quality Barrel Upgrading: RDS/VRDS and OCR/UFR
of the distillate depends strongly on the feed properties Catalysts
and unit pressure—such products usually need further 10.6.1 Introduction
hydrotreating to then be suitable for the clean fuel pool. The bottom-of-the-barrel (i.e., atmospheric residue [AR,
The product VGO makes an excellent FCC feedstock, and 345ºC+] or vacuum residue [VR, 565ºC+]) is of lim-
as a consequence, some FCC-PT units of moderate pressure ited direct use because of its high specific gravity; low
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234 Petroleum Refining and Natural Gas Processing

and HDMCR functions are more important for low-sulfur

Table 10.8—Albemarle’s Fulfilled MHC fuel oil production and delayed coker feed generation,
Catalytic Technology whereas HDM, HDMCR, and HDN functions are of more
Size/ Composition/ emphasis for RFCC feed generation.
Product Shape Type Characteristics The length of a RDS/VRDS run is limited by the metal
capacity of the catalyst system and the metal concentration
KF 1014 1.5E, 3E NiMo Moderate activity—
amorphous distillate selective of the residuum processed [63]. In practice, the needs of a
refiner are met by balancing the metal capacity of a catalyst
KF 1015 1.5E, 3E NiMo Moderate activity— system with its upgrading capability to meet a regular main-
amorphous distillate selective tenance turnaround schedule. The commercialization of the
KF 1022 1.5E CoMo Moderate activity— OCR process in 1991 using a spherical HDM catalyst that
amorphous distillate selective can be replaced onstream enables refiners to retrofit exist-
ing RDS units for handling heavier residuum feed of higher
KF 1023 1.5E NiMo Moderate activity—
metal content while maintaining or improving run length.
amorphous distillate selective
Residuum hydrotreating catalyst development efforts
KC 2301 1.5E, 2E NiMo zeolitic High activity— at Chevron over the past few decades have led to the com-
distillate selective mercialization of many catalysts (Table 10.10). The heavy
KC 2601 1.5E, 3E NiMo zeolitic High activity— investment in technology continues at Advanced Refining
distillate selective Technologies (ART), a joint venture between Chevron and
Grace Davison since 2001. Currently, ART supplies more
KC 2602 1.5E, 3E CoMo zeolitic High activity—
than half of residuum hydrotreating catalysts worldwide.
distillate selective

10.6.2 General Catalyst Functionality and

ydrogen-to-carbon ratio; and high concentrations of sulfur,
h Deactivation Mechanism
nitrogen, nickel, vanadium, and other impurities. The resid- Residuum consists of asphaltenes (large polynuclear aromatic
uum desulfurization (RDS) or vacuum residuum desulfur- compounds insoluble in paraffinic hydrocarbons) surrounded
ization (VRDS) process, in combination with the on-stream by resins in micelle form to remain dispersed in saturates
catalyst replacement (OCR) or upflow reactor (UFR) process and aromatics [64]. The metals (nickel, vanadium, etc.) are
possibly present upstream, can achieve greater than 98 % typically present as high-molecular-weight organometallic
hydrodemetalization (HDM), greater than 95 % HDS, greater
than 70 % HDN, and further upgrade residuum via microcar-
bon residue (MCR) reduction (HDMCR) of greater than 70 % Table 10.10—Resid Hydrotreating
and VR conversion of up to 60 liquid volume (LV) % [58,59]. Catalysts Introduced since RDS/VRDS
The upgraded residuum can be used as low-sulfur fuel oil Commercialization
or as feed to residuum FCC (RFCC) and delayed coker units Year HDM Catalyst HDS Catalyst
[60,61]. Typical ranges of feed and product properties of the
OCR/UFR-RDS process are summarized in Table 10.9. 1969 GC-101
The early RDS units contained catalysts adapted from 1974 ICR 105
VGO hydrotreating catalysts to remove sulfur and generate
1975 GC-100, 102
low-sulfur fuel oil. Because of the deposition of metals in
feed on the surface and in the small pores of these catalysts 1979 GC-105, 106, 107
as sulfides, the HDS activity fouls rapidly when metal con-
1981 ICR 121
centration in the feed exceeds 10–20 ppm [62]. The catalyst
system used in the RDS/VRDS process now consists of 1982 ICR 122
layered catalysts so that the residuum is sufficiently demet- 1984 GC-125, 130
alized by catalysts of high HDM activity before contacting
catalysts of high conversion activities (i.e., HDS, HDN, and 1985 GC-102, 107
HDMCR). The layered catalyst system allows effective han- 1987 ICR131
dling of residuum of high metal content for an extended
period of time and can be tailored to emphasize specific 1988 ICR132
catalytic functions depending on the feed properties and 1990 ICR 133, 122H ICR 135, 145, 146
the end use of the upgraded residuum. For example, HDS
1991 ICR 138 ICR 137

1995 ICR 148

Table 10.9—Typical Feed and Product
Properties of OCR/UFR-RDS Processes 1996 ICR 149
AR Feed RDS Product 1997 ICR 151
API 10–20 16–23 1999 ICR 153
Sulfur (wt %) 2–5 0.25–0.70 2000 ICR 161
CCR (wt %) 8–17 3–7 2001 ICR 167
Nickel + vanadium (ppm) 40–160 5–25 2004 ICR 165 ICR170, 171
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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Chapter 10 n Advances in Catalysts for Refining Processes 235

compounds (such as metalloporphyrins) in the asphaltene access the active sites inside of the conversion catalyst pellets.
and resin fractions of residuum. In contrast, most of the Conversion catalysts have limited HDM activity because
sulfur is often present as lower molecular weight compounds of the much-hindered diffusion of large organometallic
in the aromatic and resin fractions [65]. This difference in molecules inside of the catalyst pellets.
distribution between metals and sulfur, combined with the To better manage the large-pore (HDM) versus small-
fact that the deposition of metals in the feed as sulfides on pore (conversion) dilemma, a typical RDS/VRDS catalyst
catalyst is irreversible, makes physical properties of residuum system is layered such that the HDM activity is higher
hydrotreating catalysts as important as chemical properties toward the inlet where the metal concentration in residuum
for their performance, as discussed later in this section. is the highest. Conversion activity is higher toward the
Residuum hydrotreating catalysts typically consist of outlet so that residuum of decreasing metal concentration
γ-alumina support impregnated with active metals (i.e., molyb- trickles down the reactor, contacting increasingly more
denum promoted with nickel or cobalt or both). These active active conversion catalysts.
metals are initially present as oxides on the alumina support The deactivation of the RDS/VRDS catalyst system
and are converted to corresponding sulfides in situ. The metal proceeds through a characteristic initial rapid deactivation
sulfides are the catalytically active phases in the reaction envi- period, middle-of-run slow deactivation period, and end-of-
ronment. The molybdenum loading is typically sufficient so run ultimate deactivation period (Figure 10.16). The average
that the molybdenum sulfide phase is formed at high cover- catalyst temperature of a RDS/VRDS unit is raised to meet
age and high dispersion on the alumina support. The nature a product specification (usually sulfur content). Figure 10.16
of active sites involved in reactions occurring in residuum shows the temperatures required for meeting sulfur target
hydrotreating is highly complex because of the large variety versus metals deposited on the catalyst system as a measure
of molecules in the feed. Studies conducted with much lighter of run length. During the initial period of contact with
oils and model sulfur compounds suggest that the edge sites of residuum, the rapid buildup of coke on catalyst (up to 20
the MoS2 slab decorated by cobalt or nickel are involved in the wt %) leads to loss of catalyst surface area and pore volume.
HDS reaction [66]. It is possible that other parallel reactions The asphaltene fraction in residuum is a major contributor to
such as HDN and HDMCR may involve different sites. coke formation. Metal deposition has also been suggested
The activity (HDM, HDS, etc.) and life of residuum to contribute to the initial rapid deactivation period [67]. The
hydrotreating catalysts are strongly affected by their physi- slow deactivation in the middle of the run is primarily due
cal properties, including surface area, pore volume, and pore to accumulation of metal sulfides, which reduces catalyst
size distribution [63,67]. In general, physical properties porosity and surface area. The buildup of metal sulfides
that favor HDM activity are undesirable for HDS activity eventually reduces the mesoporosity to the extent that
and vice versa. This point is illustrated in Figure 10.15, which heteroatom-containing molecules are excluded from the
shows the inverse correlation of HDM and HDS activity catalysts, leading to the ultimate deactivation.
with pore size. As the average pore size increases, so does Analysis of spent catalysts reveals that the extent of
the diffusion rate of high-molecular-weight organometallic penetration of metal sulfide deposits into the catalyst pel-
compounds inside of the catalyst pellet, leading to better lets decreases significantly as the pore size decreases from
HDM activity. On the other hand, the larger pore size of HDM the top (HDM section) to the bottom (HDS section) of
catalysts also means lower surface area for supporting the catalyst bed. Metal sulfide deposits are spread fairly
active metals, which results in lower conversion activity. uniformly over the cross-section of an HDM catalyst pel-
Conversely, conversion catalysts have smaller pores and let near the reactor inlet. On the conversion catalyst near
higher surface area. The higher surface area in conversion the reactor outlet, most metal sulfide deposits are con-
catalysts allows better dispersion of MoS2 slabs at higher centrated near the edge of the catalyst pellet. This high
molybdenum loading on the alumina support to form more concentration of metal sulfide deposits near the catalyst
active sites. The smaller mesopores are large enough for edge is responsible for pore mouth plugging, which causes
most of the lower molecular weight sulfur compounds to the ultimate deactivation.

High High
Temperature Required to Meet Sulfur Target
HDS Activity

HDM Activity

Low Low
Increasing
Pore Size (Angstrom) Metals on Catalyst (g/cc)

Figure 10.15—HDS and HDM activity trade off as pore size Figure 10.16—Typical deactivation curve for RDS catalyst
changes. system.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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236 Petroleum Refining and Natural Gas Processing

10.6.3 Practical Considerations for Residuum

ICR132
Hydrotreating Catalysts
The HDM catalysts used in RDS/VRDS processes often have ICR161/167

Relative Performance
several grades of nominal diameters. At the reactor inlet,
catalyst size gradually decreases so that particulates present
in residuum are filtered out over several layers. This catalyst
grading practice reduces the tendency of particulates to
cause excessive pressure drop increase, especially in the bed
containing the catalyst of the smallest size. The physical
grading technique is based on extensive refinery experience,
dating back to when Chevron first developed top-bed grading
Metal Capacity HDV HDS
technology to minimize the effect of high levels of insoluble
iron in some California crudes on refinery operations [62]. Figure 10.17—Improved performance of new HDM catalysts
The spherical catalysts for the UFR/OCR process are vs. traditional HDM catalyst.
designed following principles similar to HDM catalysts
for RDS/VRDS. However, these spherical catalysts have A new conversion catalyst, ICR170, is used at the front end
specific density requirements to maintain the plug flow of of the conversion bed to increase tolerance of the conversion
catalyst down the OCR reactor. The plug flow of catalyst and catalyst bed to metal leakage from the HDM section without
the countercurrent feed flow maximize catalyst effectiveness significantly reducing the HDS activity. The metal capacity
by exposing the most metal-loaded and least active catalyst to of ICR170 is 20 % higher than that of traditional conversion
the fresh residuum before being removed from the reactor. catalyst ICR131. Figure 10.18 shows the HDMCR, HDS,
It is also critical for these spherical catalysts to have high and HDV activities of ICR170, 131, and 137. The HDS and
resistance to attrition because fines generated from the HDMCR activities of ICR170 are better than those of ICR137
moving bed operation can change the flow regime inside of with a slight compromise in HDV activity. Another conversion
the reactor and contaminate other processes downstream catalyst, ICR171, of very high conversion activity is suitable for
of the OCR unit. The spherical γ-alumina support materials applications requiring very low product sulfur (0.1–0.5 wt %).
for UFR/OCR catalysts are formed from pseudoboehmite This deep conversion catalyst is used at the end of the con-
via a Grace proprietary process. version bed where metal concentration has been sufficiently
The γ-alumina support materials for RDS/VRDS catalysts reduced. The HDS and HDMCR activities of ICR171 are supe-
are formed from pseudoboehmite by peptization, extrusion, rior to those of the deep conversion catalysts ICR153 and 135
and high-temperature calcination. The extrudates typically with some tradeoff in HDV activity, as shown in Figure 10.19.
have a multilobe cross section. This shape provides a higher The main focus of OCR/UFR catalyst development has
ratio of external surface area per unit volume such that higher been to improve physical properties of the spherical support.
diffusion rate, higher contaminant metals tolerance, and
lower pressure drop buildup rate can be achieved compared
ICR131
with cylindrical extrudates [63,68]. The pseudoboehmite raw
ICR137
Relative Performance

materials are custom manufactured at Grace by precipitation

of acidic and basic solutions of aluminum salts, followed by ICR170
washing and drying under complex operation conditions [69].

10.6.4 Developments and Improvements

The backbone of the RDS/VRDS catalyst system has tradi-
tionally included three catalysts: ICR132 of excellent metal
removal activity and high metal capacity, ICR137 of good
conversion activity (i.e., HDS, HDMCR, and HDN) and high
MCR HDS HDV
metal tolerance, and ICR131 of high conversion activity and
moderate metal tolerance. Figure 10.18—Comparison of HDMCR, HDS, and HDV activities
To meet the demand for a catalyst system capable of of three conversion catalysts.
handling heavier feedstock, HDM catalysts of higher metal
removal activity and metal capacity and conversion catalysts ICR135
of higher sulfur, nitrogen, and MCR removal activity are ICR153
both desired. Better engineering of conversion and HDM ICR171
Relative Performance

activity tradeoff can also contribute to higher cumulative

HDS and HDM activity for the full system.
A new HDM catalyst, ICR161, has very high HDM
activity to better protect the conversion catalysts and extra
metal capacity to delay the onset of ultimate deactivation
in the HDM bed. Another new HDM catalyst, ICR167,
improves HDS and HDMCR activity of HDM section with-
out significantly reducing metal capacity. The ICR161/167
MCR HDS HDV
combination has higher HDM activity, metal capacity, and
HDS activity than traditional HDM catalyst ICR132, as Figure 10.19—New deep conversion catalyst of superior
shown in Figure 10.17.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
HDMCR and HDS activities.
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Chapter 10 n Advances in Catalysts for Refining Processes 237

The original ICR138 has been expanded into three grades gain of impurity removal capability and capacity in OCR/
of increasing size to improve reactor hydrodynamics and UFR-RDS/VRDS processes, allowing more challenging
accommodate feedstock with a wider range of properties. feedstock to be processed. Meanwhile, the new additions
The new OCR/UFR catalyst ICR165 commercialized in to the extensive family of residuum hydrotreating catalysts
2004 has enhanced HDS function compared with ICR138. provide more flexibility in customizing a catalyst system to
meet/exceed specifications for downstream applications.
10.6.5 Design of RDS/VRDS Catalyst System Residuum hydrotreating catalyst technology is continu-
The extensive range of ART residuum hydrotreating catalysts ously challenged by the increasing level of impurities in resid-
allows great flexibility in designing an RDS/VRDS catalyst uum feedstock. The industrial trend of increasing demand
system for various feedstocks depending on the end use of for high-value petroleum products [70,71] and decreasing
the upgraded residuum. The design of a layered catalyst sys- demand for fuel oil from residuum also plays an important
tem is a compromise between conversion activity and metal role in guiding next-generation catalyst developments.
capacity. A good kinetic model considering feed reactivity
and deactivation rate relative to metal and coke buildup is 10.7 Solid Acid Catalysts for Motor Fuel
essential for the task. Extensive pilot plant studies have been Alkylate
conducted at Chevron to quantify feedstock reactivity dif- Replacing toxic liquid acids (e.g., hydrofluoric and sulfuric
ferences on various residuum hydrotreating catalysts. These acid) with solid acid catalysts is a challenging goal for isopar-
differences are largely due to the different distribution of affin alkylation technology because of the rapid deactivation
heteroatoms in asphaltenic and nonasphaltenic fractions of of solid acid catalysts. Although zeolite catalysts (e.g., USY
residuum from various sources around the world. zeolite and zeolite β with sufficient acidity for alkylation)
By varying the selection and relative volume of HDM have shown appropriate activity, most have life measured
and conversion catalysts, catalyst systems can be designed in hours or even minutes. The catalyst design concept for
to accommodate refiners processing residua of a wide solid alkylation is to exhibit (1) high activity to enhance
range of contaminant levels. Two illustrative catalyst sys- alkylation reactions and limit side reactions, and (2) the
tems of different HDS deactivation pattern relative to metal stability and regenerability characteristics to be repeatedly
capacity when processing an AR of Middle Eastern origin fully recovered at near-reaction conditions.
are shown in Figure 10.20. A refiner that needs to meet very Solid acid catalysts applied for the AlkyleneTM process,
strict sulfur specification and uses light residuum feed is the AlkycleanTM process, and the Fixed-Bed Alkylation
likely to prefer catalyst system A, which limits the level of (FBATM) process are shown in Table 10.11.
metals in residuum that the refinery can process without
suffering earlier-than-planned shutdown. Refiners with less Table 10.11—Solid Acid Catalysts Applied
strict sulfur target are likely to prefer catalyst system B for the Alkylation Processes
with extra metal capacity for processing heavier feedstock
of lower cost. Process Licensor Catalyst

Alkylene TM
UOP Supported metal catalyst
10.6.6 Summary
A new generation of residuum hydrotreating catalysts Alkyclean TM
ABB Lummus Global Supported noble metal
zeolite
has been developed as a result of research and development
efforts at ART that builds on the expertise in residuum Akzo Nobel Catalysts
hydrotreating accumulated over the past few decades at
FBA TM
Topsøe Supported liquid catalyst
Chevron. These advances in catalyst technology lead to a net

400
Temperature required to reach sulfur target (°C)

System A System B
390

380

370
base base+30 %
Metal on Catalyst (g/cc)

Figure 10.20—The design of an RDS catalyst system is a compromise between conversion activity and metal capacity. --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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238 Petroleum Refining and Natural Gas Processing

10.7.1 Alkylation Chemistry an ester. The ester is less strongly adsorbed on the solid
The reaction is initiated by the formation of tertiary butyl support than the acid and moves downstream into the
carbenium ions (i-C4+) on the acid sites of the solid catalyst olefins’ lean and acid rich environment with the hydrocar-
as shown in Figure 10.21. The alkylation of C4 olefins with bon flow. In a reaction zone of low olefin concentration
this i-C4+ on the catalyst surface forms i-C8+ (carbenium) and higher acid activity, the ester reacts with isobutene to
ions. Hydride transfer from another isobutene molecule form alkylate and an acid molecule, which prevents olefin
forms a C8 paraffin product and another carbocation that oligomerization.
will propagate the reaction. In this mechanism, a high The spent acid, having a weaker interaction with the
isobutene-to-olefins ratio in the reaction environment and support than the active acid, moves downstream of the
high hydrogen transfer reaction rates favor the formation acid zone and is removed for recovery outside of the reac-
of trimethylpentane (TMP), which has a high octane value tor system. Thus, the catalyst activity can be maintained
and is the more desirable C8 product when compared with without interruption of the alkylation operation. FBATM
dimethylhexane. pilot plant results with different feedstocks are shown in
When reaction time is increased, isomerization equilib- Table 10.12. The research octane number (RON)/motor
rium favors the formation of lower octane dimethylhexane. octane number (MON) of the alkylate from the FBATM pro-
The optimal contact time to maximize alkylate product cess using FCC-derived mixed butylenes as a feedstock was
quality is critical. Lower temperature and higher isobutene- 95/92 at an I/O of 14 and reactor inlet temperature of 8°C.
to-olefin ratio (I/O) in the reaction environment increase The product quality reflects the variation in feed quality
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

overall selectivity toward TMP over lower octane side reaction and operating conditions. Increasing the inlet temperature
products. from 8 to 31°C results in a decrease in product quality of
2–3 RON and 1–2 MON. Half reduction in feed I/O from 14
10.7.2 Catalyst for AlkyleneTM to 7 lowers the RON by 2 and the MON by 1 octane number.
The supported metal catalyst was developed based on A lower feed I/O reduces utility costs and improves the
UOP’s extensive expertise in developing supported platinum process economics.
catalysts such as the CCR platforming process [73]. Metals
on the catalyst hydrogenate and strip unsaturated, high- 10.7.4 Catalyst for AlkycleanTM
molecular-weight hydrocarbons blocking active sites on the The noble zeolite-based catalyst that contains no halogens
catalyst surface by contacting the catalyst with hydrogen has acid sites with sufficient strength for alkylation and
and isobutene. The catalyst has optimal particle size and exhibits the required activity, stability, and regenerability
pore distribution to allow for good mass transfer into and characteristics [72]. In Akzo’s patents, the solid acid catalyst
out of the catalyst. The catalyst, which has high physical is Y zeolite or zeolite β with 0.01–2 wt % of Group VIII noble
strength, has been demonstrated to have very low attrition metal, especially palladium or platinum [75].
rates by extensive physical testing.

10.7.3 Catalyst for FBATM Table 10.12—FBATM Pilot Plant Results with
The FBATM process applies a unique fixed-bed reactor Different Feedstock and Product Quality
coupled with a liquid superacid catalyst adsorbed on a Sensitivity to Reactor Inlet Temperature and
particulate porous solid [74]. The various components I/O [74]
such as liquid superacid, reaction intermediates, and
hydrocarbons interact with the porous solid according Feed 1 Feed 2 Feed 3
to their individual polarities as follows; fresh liquid acid > Feedstock, wt %
spent liquid acid > intermediates (ester type intermediates) >
Propane 0.1 0.2 17.7
hydrocarbons. The catalyst zone slowly migrates through
the supported bed in the direction of the hydrocarbon 1-Butene 2.3 15.6 9.3
flow. The migration of the catalyst zone is closely coupled
2-Butene 63.4 29.2 18.5
to the alkylation chemistry and to the interaction between
various components and the catalyst. The liquid hydro- Isobutene 0.3 19.8 7.3
carbon phase passes through the fixed bed in plug flow.
Pentenes 0 0.4 5.2
The olefins in hydrocarbons react with the acid to form
Isobutene 0.7 26.7 19.3

Other paraffins 33.2 7.7 22.6

i-Octane Butene
Cat- -i-C4+ Butadiene 0 0.4 0.1

Operating conditions

I/O 15 14 14 7 15
H-Transfer Alkylation
Reactor inlet 5 8 31 8 5
temperature, °C

Product quality
i-Butane Cat- -i-C8+ RON 98 95 92 93 93

MON 95 92 91 92 91
Figure 10.21—Alkylation reaction mechanism [72].
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Chapter 10 n Advances in Catalysts for Refining Processes 239

Moreover, the catalyst is resistant to potential feed from light natural gas, the reaction activity of which is 3–4
impurities, such as water, oxygenates, sulfur compounds, times higher than current market catalysts that have similar
and butadiene. The catalyst is regenerated with dissolved H2 activities to one another.
under regeneration conditions close to reaction conditions TOYO has licensed the manufacturing right of the
by switching the fixed-bed reactor. The durability of the ISOP catalyst to Sued-Chemie Catalyst Japan Ltd. and Sued-
catalyst was demonstrated over hundreds of cycles of reju- Chemie Catalyst, Inc. of the United States. The commercial
venation and multiple moderate temperature regeneration. track records in the ISOP catalyst are more than 15 years
Table 10.13 shows the effect of various regeneration for fuel cell plants and more than 10 years for large-scale
procedures on the life of the regenerated catalyst. The cata- industrial plants. The ISOP catalyst has been authorized by
lyst activity can be repeatedly fully recovered by vapor phase Kellogg Brown & Root (KBR), one of the renowned licen-
stripping with H2 at 230°C. However, such a regeneration sors of the ammonia process in the world, and has been in
procedure is not practical because the heating up and cool- commercial operation in Japan, Bangladesh, Germany, and
ing down periods required at the start and end of a regenera- Indonesia.
tion cycle take too much time. Catalyst can be regenerated Ni/Al2O3 with alkaline or Ni/MgO constitutes other
in the liquid phase with dissolved H2 at regeneration condi- currently available conventional catalysts for large-scale
tions that are close to alkylation reaction conditions. plants. The pore structures of these catalysts become similar
to each other because of sintering of supports in operations
10. 8 Catalysts for Hydrogen at elevated temperatures (500–800°C) whereas their fresh
Production properties are quite different from each other [76]. These
10.8.1 Steam Reforming Catalysts catalysts have commonly large diffusional resistance (e.g.,
A highly active steam reforming catalyst, named ISOP the effectiveness factor at the reformer inlet is 0.2 and that
catalyst, was developed by Toyo Engineering Corporation at the outlet is typically 0.05), and every catalyst shows a
(TOYO) for hydrogen and synthesis gas (syngas) production similar apparent activity within a few hundred hours of
operation. On the other hand, ISOP catalyst prepared by
thermally stable components has a bimodal pore structure
Table 10.13—Effect of Various having mesopore, or micropore in a case, and macropore
Regeneration Procedures on the Life of together as shown in Figure 10.22 so that the effectiveness
Regenerated Catalyst [75] factor increases without any sacrifice of nickel dispersion.
Temperature Pressure Time Catalyst The concept on the increasing activity is shown in
(°C) (Bar) (h) Life (h) Figure 10.23. The macropore in the bimodal structure con-
tributes to increasing the effective diffusivity (Dev) into active
Fresh 10
sites. Further, nickel was designed to be supported so as
catalyst
to disperse more finely and retain the finer condition [77].
H2 gas* 230 21 1 10 ISOP catalyst developed under this concept is 3–4
H2 gas* 230 21 1 10
times as active as conventional catalysts on the basis of
reaction rate. ISOP catalyst in the spoke shape, which has
H2 gas* 230 21 1 10 a large geometric surface area per catalyst particle, was
i-C4 liquid 90 21 66 6.5 partially charged in a 1500 t/day-class ammonia plant after
with confirming the high performance in a pilot plant [78]. The
dissolved H2 catalyst has shown for more than 3 years the expected tem-
perature decrease on the reformer tube, which is a sign of
i-C4 liquid 115 30 18 4
the high activity. Observed activities of ISOP catalyst in the
with
dissolved H2
ammonia plant agree with those observed in the pilot and
laboratory experiments at a 95 % confidence limit range as
*Repeated regeneration
shown in Figure 10.24.

Primary particle
Active metal is supported Meso pore Macro pore
on the particle

Conventional catalyst ISOP catalyst

(Unimodal) (Bimodal)
Figure 10.22—Schematic structure of catalysts.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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240 Petroleum Refining and Natural Gas Processing

I S O P catalyst

Large effective Macro pore

diffusivity, Dev

Large surface area Large support Meso/Micro pore

of active metal, S Ni surface area

Technology retaining
well-dispersed metal

Condition of active metal Support structure

( Dev . S Ni ) 0.5 . (geometric surface area)

Activity ∝
Figure 10.23—Concept of high activity in ISOP catalyst.

4,000 reaction is competitive to the steam reforming reaction

Evaluation of Lab. evaluation
Pilot of discharged
(i.e., a gasification reaction of hydrocarbons).
commercial plant
3,000 operation catalysts The mechanical strength of the conventional catalysts
is approximately 400 N before use. ISOP catalyst retained
Reaction Rate

Spoke a higher strength than the value of the conventional one in

2,000 ISOP
catalyst
the 2 years of operation.
On sulfur resistance, ISOP catalyst proved in the opera-
1,000 Spoke tion that no special treatment is required other than an
conventional ordinary desulfurization system (e.g., CoMo + ZnO).
catalyst
0
0 0 0 00 0
2 4 5 , 00 0 , 00 0 5, 0 0 0 0, 0 00 5 , 00 0 10.8.2 Benefits of ISOP Catalyst in Box-Type
1 1 2 2
Reformer
changing ISOP catalyst reduces the plant’s capital and operating costs.
Time / h
scale
Because the steam reformer is operated at high temperatures
Figure 10.24—Activity of ISOP catalyst (Solid lines are from an equilibrium requirement, there were implicit
estimated activities from pilot operations. Dotted lines prospects that no successful result would be obtained by
indicate 95 % confidence limit range). increasing catalyst activity because of slow heat transfer.
However, precise simulating studies from a plant-designing
Commercial catalysts should have proper performance viewpoint verified benefits with highly active ISOP catalyst.
properties (Table 10.14). The conventional catalyst charged The active catalyst proceeds via endothermic reaction
in the ammonia plant, which has the lowest level of acid much more and decreases the tube metal temperature.
amount, is the most coking-resistant in conventional catalysts Figure 10.25 shows two different, but typical, tube tem-
for the light natural gas. ISOP catalyst and the conventional perature profiles in a top-firing furnace for an ammonia
one were discharged from each tube at a periodic scheduled plant. The maximal peak temperatures are at 20–30 % in
shutdown after 2 years of operation. An amount of depos- the down-tube position. In both cases the ISOP catalyst
ited carbon in ISOP catalyst is approximately one third that (thicker lines) decreases the peak temperatures by approx-
in the conventional catalyst, which verified that the ISOP imately 30°C compared with the case using a conventional
catalyst is more resistant to the coking in the commercial catalyst (thinner lines). The temperature decrease of the tube
operation. The larger coking resistance of ISOP catalyst makes the temperature difference larger between the flue gas
is understood because of a lower concentration of coke and the tube wall, which increases the heat transfer much
precursor on the well-dispersed nickel because the coking more: The heat transfer due to radiation is proportional to
the difference in the temperatures, each raised to the fourth
power. Further, the higher activity makes the approach to
Table 10.14—Commercial Performance equilibrium smaller, which requires a lower temperature at
of ISOP Catalyst in Comparison with the outlet to obtain an expected production rate. The lower
Conventional Catalyst temperature requires less fuel. These effects by the ISOP
catalyst achieve 1.6–2.0 % saving of reformer fuel.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Activity 3–4 times higher The higher activity also extends the life of the reformer
Coking resistance Higher, one third of deposited tube in existing plants [78]. Although the effect is highly
carbon in 2 years operation dependent on an original design and its operating condi-
tions, a decrease of 20°C of the tube temperature can extend
Mechanical strength Higher, before and after operation the tube life by 2.5 times; a 30°C decrease can theoretically
Sulfur resistance Equivalent extend tube life by 3.7 times. On the other hand, an increase
in production is expected when the tubes are operated at
Steam resistance Equivalent
the same high temperatures in the same manner.
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Chapter 10 n Advances in Catalysts for Refining Processes 241

900

one graduate = 100 C

heating fluid
850

Temperature
Maximum Tube Wall
Temperature / C
800
750
process fluid
700
650 Conventional catalyst 0.0 0.2 0.4 0.6 0.8 1.0
ISOP catalyst
600
0.0 0.2 0.4 0.6 0.8 1.0

900

Heat Flux
850
Maximum Tube Wall
Temperature / C

800
750
700 0.0 0.2 0.4 0.6 0.8 1.0

650 Conventional catalyst 100

ISOP catalyst

CH4 / dry mol %

600 80
0.0 0.2 0.4 0.6 0.8 1.0
Fraction down tube / - 60

Figure 10.25—Tube wall temperature profiles in typical steam 40

natural gas reformers.
20

For newly built plants, the highly active catalyst can 0

0.0 0.2 0.4 0.6 0.8 1.0
reduce the capital cost. The temperature decrease makes
Tube fraction / -
thinner tubes applicable [78], which provides a large cost
ISOP catalyst charged
reduction.
Conventional catalyst charged
10.8.3 Benefits of ISOP Catalyst in Heat-
Figure 10.26—Profiles of temperature, heat flux, and methane
Exchanger Reformer concentration in a heat-exchanging reformer. The number of
The box-type reformers have established their position tubes when ISOP catalyst is used is 40 % less than that when a
in industries with long experience. However, they have a conventional catalyst is used.
disregarded demerit of large firing duties that require com-
plicated and expensive heat recovery systems. To improve
this problem, heat-exchanger reformers with shell-and-tube leads to the cost reduction of the shell-and-tube structured
structure have been proposed in combination with a con- reformer.
ventional box-type reformer or an autothermal reformer.
These reformers enable higher heat efficiency; however, 10.8.4 Recent Development in Water-Gas Shift
they are structurally so complicated that a compact design Catalysts for Applications in Polymer Electrolyte
is strongly required. Fuel Cells for Household Power Units
A highly active catalyst is a breakthrough technology In this section, the recent development in water-gas shift
to solve this problem. ISOP catalyst reduces the reformer (WGS) catalysts, particularly for applications in polymer
in size and cost. A design example of a heat-exchanging electrolyte fuel cells (PEFCs) for household power systems, is
reformer for methanol production is shown in Figure 10.26 reviewed. The difficulty of meeting the stringent operating
The figure shows that the reformer using ISOP catalyst requirements with the conventional copper-zinc (Cu-Zn)-
can produce a similar amount of syngas with a 40 % less type catalyst led to the development of the noble metal-based
tube number than that using a conventional catalyst. In the WGS catalysts in search of a new replacement. However,
case of applying ISOP catalyst, the process gas temperature at least for this particular application, use of noble metal-
decreases (thicker line) and the temperature difference based WGS catalysts for various reasons seems to be far
increases. Now, particular attention is paid to the case in from the practical use. Instead, the reinvestigation of the
which an increasing ratio of the temperature difference “old” Cu-Zn-type catalyst in this “new” WGS operating
using ISOP catalyst with the heat-exchanging reformer is environment led the way to the development of the newly
much larger than the case with the box-type reformer. In improved Cu-Zn catalyst.
the heat-exchanging reformer, the temperature difference The WGS reaction was originally developed to increase
is essentially small because of a lower temperature of the hydrogen yield while decreasing carbon monoxide (CO)
heating fluid than that by the burner heating in the box-type concentration from synthesis gas, which was required for
reformer. The larger temperature difference requires the ammonia production. The synthesis gas produced from a
smaller area of the heat transfer, which can be expressed in steam reforming reaction usually contains several to 10
increasing heat flux as shown in the middle figure of Fig- vol % CO, at which level ammonia synthesis catalysts are
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--

ure 10.26. The reduction of the heat transfer area directly poisoned; therefore, a high degree of CO removal must be
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242 Petroleum Refining and Natural Gas Processing

achieved. The WGS reaction is a reversible and exothermic redox. In the associative mechanism, hydroxyl groups on
reaction (Eq 10.2) to the right, implying that a lower CO the support surface and CO react to form surface formate
concentration (higher CO conversion) at equilibrium is species followed by its decomposition into H2 and CO2
favored at lower temperatures. assisted by gaseous water [99–101]. In the redox mecha-
nism, oxygen is supplied by the lattice oxygen in the sup-
CO(g) + H2O(g) ↔ CO2 (g) + H2 (g) ΔH port, which reacts with CO adsorbed on the metal to form
= –41.2 kJ/mol (10.2) CO2. The oxygen vacancy is regenerated by H2O, forming
H2 [98,102,103].
Industrially, the WGS reaction is performed in two Azzam et al. studied Pt/CeO2 and Pt/TiO2 using in situ
steps where a high-temperature shift (HTS) reaction is Fourier transform infrared (FTIR) spectroscopy and transient
followed by a low-temperature shift (LTS) reaction. The for- kinetic studies to elucidate possible mechanisms for Pt/
mer reaction is performed at approximately 300–450°C and CeO2 and Pt/TiO2. In the Pt/CeO2 system, surface formate was
the corresponding catalyst must have a high durability in seen to form on the support, which reacted with gaseous H2O
this temperature range. The major HTS catalyst used today to form CO2, H2, and hydroxyl groups (redox mechanism).
is the Fe2O3-Cr2O3-type metal oxide catalyst, which has been In Pt/TiO2, the reaction possibly proceeded via redox and
basically unchanged for nearly a century [79]. The active the formate route with redox regeneration. It was concluded
component of this catalyst is Fe3O4, and the role of chromia that the reducibility of support and the stability of formate
is to prevent sintering of Fe3O4. and carbonate species together determine the reaction
In the 1960s, the Cu-ZnO base LTS catalyst was devel- pathways for WGS [84].
oped and replaced the old scrubbing method, which used a Panagiotopoulou et al. [89] investigated Pt, Rh, Ru, and
copper ammonium formate aqueous solution for removal Pd catalysts over partially reducible metal oxide supports.
of carbon oxides [79]. The LT-WGS reaction is performed They reported that Pt and Pd showed relatively high activity
between approximately 180 and 250° C, and the active and that Rh and Ru had intermediate activity. The researchers
component of the LTS catalyst is copper metal whereas calculated the activation energy (Ea) of M/CeO2 and M/TiO2
zinc oxide (ZnO) acts as the support for the copper. This (where M represents various metals) and found that the
catalyst is sensitive to thermal sintering, exposure to air is values of Ea did not depend on the nature of the metallic
dangerous because of its pyrophoricity upon reduction, and phase but only on the nature of the support. This evidence
condensation of steam must be avoided because catalyst suggested that the key contribution factor for the activation
activity is drastically reduced in wet conditions [80]. energy originates from a reaction step associated with the
These problems are usually not much concern for metal oxides. Furthermore, they also suggested that the
typical chemical plants unless unforeseen events happen reducibility of the support possibly influences the redox
during the operation of the reactors. However, applica- mechanism or formation of surface formates by affecting
tions in PEFCs, particularly for household power systems, the surface hydroxyl groups.
require a daily startup and shutdown (DSS) followed by Iida et al. studied Pt supported on TiO2 (rutile and
purging of the combustible gases with air or steam. Low anatase), ZrO2, and Al2O3 using various spectroscopic and
durability of Cu-ZnO catalysts under oxidizing conditions temperature programming techniques including transmission
in the presence of steam has led researchers in the field electron microscopy (TEM), X-ray photoelectron spectros-
to investigate other catalytic systems such as noble metal- copy (XPS), temperature programmed desorption (TPD),
based catalysts to replace the commercial Cu-ZnO catalyst and FTIR. It was found that Pt/TiO2 was much more active
from the PEFC applications. Section 10.8.5 summarizes the than Pt on ZrO2 and Al2O3 although the dispersion of Pt
recent advancements in such catalysts. over TiO2 was lower than that on ZrO2 and Al2O3. Between
Pt supported on rutile TiO2 and anatase TiO2, the former
10.8.5 Noble-Metal-Based WGS Catalysts had a higher dispersion. XPS revealed that the Pt was
Platinum (Pt)- [81–95], rhodium (Rh)-, ruthenium (Ru)-, slightly negatively charged compared with Pt0, which may
palladium (Pd)- [89,96], and iridium (Ir)- [91,92] based indicate the donation of electrons from TiO2 to Pt. Because
catalysts have been investigated over various support metal this feature was not observed over ZrO2 or Al2O3, TiO2 was
oxides for a LTS reaction in the last decade. Among the seen to have more effect in the electronic state of Pt than
many noble metals studied, Pt-based catalysts supported other supports. From the TPD profiles of CO adsorption, it
on reducible metal oxides offer promising results. In this was shown that the strength of Pt-CO bonding on TiO2 sup-
reaction, activation of H2O is more difficult than CO activa- port was weaker than other supports. This suggested that
tion because H2O is thermodynamically more stable than the adsorbed CO on TiO2 was more reactive than those on
CO [97]. In the conventional Cu-ZnO system, the activation other supports. It was concluded that the support and Pt
of H2O takes place via oxidation of Cu to CuO. However, interactions could have a large effect on the activity of the
in a Cu-free system (e.g., Pt), it is known that PtOx is ther- WGS reaction [82].
modynamically unstable at the operating temperatures Although the initial activity of Pt-based catalysts was
of WGS; therefore, a chemical interaction of H2O with Pt closer (or higher in some cases) to the conventional Cu-ZnO
cannot be expected [98]. Over noble-metal-based catalyst system under certain conditions, many found that it became
systems, mechanistic investigations to address questions unstable with time-on-stream [85,88,96]. Azzam et al. [85]
including H2O activation, CO adsorption, and surface found that Pt/CeO2 deactivated because of formation of
intermediates have been performed by many researchers. stable carbonate species on the ceria surface. Because car-
It is generally accepted that there are two types of reaction bonate is known to be unstable over TiO2 [104], deactivation
mechanisms over the noble-metal-based systems: (1) asso-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
by this route would be less problematic for Pt/TiO2 and
ciative (surface formate formation) and (2) regenerative would offer an attractive solution over Pt/CeO2. However,
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Chapter 10 n Advances in Catalysts for Refining Processes 243

Pt/TiO2 also deactivated with time despite higher initial of the sample at 250°C for 1 h in a H2 stream. The XRD
activity of Pt/TiO2 than Pt/CeO2. The cause of deactivation pattern on the conventional Cu-Zn catalyst showed that
was determined to be the sintering of Pt. Pt sintering was the introduction of water over freshly reduced surface at
seen to occur when traces of formaldehyde were formed 250°C was enough to increase Cu crystalline size from 1.7 to
under the reaction conditions. A separate formaldehyde 4.5 nm. It was also shown that the Cu was oxidized to Cu2O
adsorption experiment on a reduced catalyst confirmed a and CuO in steam [105]. New Cu-Zn-Al-type catalyst was
decrease in Pt dispersion from 55 to 30 %. It was suggested shown to have a higher resistance to hydrothermal condi-
that the presence of formaldehyde in combination with the tions compared with the conventional Cu-Zn catalyst. In
presence of defect titania enhances Pt mobility on TiO2 and situ XRD pattern along with XAFS revealed that ZnAl2O4
causes Pt sintering [95]. (spinel) was formed under the reaction conditions only on
One of the attempts to overcome this problem was the new Cu-Zn-Al catalyst. Growth in crystallite size for Cu
to incorporate promoters in the Pt-based catalytic system was almost negligible (11.1 nm → 12.8 nm) after 50 cycles
[81,86–88,91,92,94]. Zhu et al. [88] reported that sodium of DSS treatment in the new Cu-Zn-Al catalyst whereas the
addition to Pt/TiO2 improved the stability of Pt/TiO2 catalyst growth for the conventional Cu-ZnO catalyst was much
by preventing Pt sintering. Farrauto and coworkers [94] larger (12.4 nm → 25.0 nm) [106]. It seems that this new
have used molybdenum (Mo) and rhenium (Re) as the pro- synthesis method enables the formation of Zn spinel under
moters over Pt/ZrO2 and improved its activity by 3-fold. the reaction conditions over which Cu sintering can be
The addition of these promoters had a positive effect on minimized because of the hydrothermally stable nature of
the thermal stability of the catalyst, possibly because of spinel. These findings are very interesting and may offer
formation of Pt-Re-Mo alloy under the reaction conditions. an attractive solution to the current problem faced in WGS
They reported that this system is currently working in com- catalysts for PEFC applications today.
mercial units. A unique operation regimen used in PEFCs for house-
Sato et al. studied the effect of Re addition to TiO2- hold power systems, in which the system is started up in
supported Pt, Pd, and Ir catalysts. Catalyst activity was the morning and shut down at night with air or steam

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
found to increase with the addition of Re over all cata- purging in between, led researchers to seek a better WGS
lysts. Turnover frequency (TOF) data of H2 formation catalyst in noble-metal-based catalysts. However, overall
were obtained over Pt, Pd, and Ir catalysts with varying cost of the PEFC power unit is still high, and reducing the
particle sizes. It was shown that although H2 formation catalyst cost is one of the difficulties faced today. Use of
rate became steady with a Re:Pt ratio greater than 1:1, the noble metals, particularly Pt, may be cost-prohibitive
TOF kept increasing with higher Re:Pt ratio, suggesting although technical hurdles could be overcome. On the
a formation of bimetallic clusters between Pt and Re. On other hand, the new type of Cu-Zn-Al catalyst, which forms
the contrary, for Ir-Re catalyst, the addition of Re resulted ZnAl2O4, seems to be promising with respect to cost and
in formation of highly dispersed nanoparticles and the performance. To successfully and widely introduce PEFC
increase in TOF was not observed. The effect of Re on acti- household power systems in the market, development not
vation energy was also studied and it was found that the only in catalyst formulation but also in operation method-
Re addition decreased the activation energy on Pt/TiO2 and ology is necessary to effectively bring down the overall cost
Pd/TiO2 but increased on Ir/TiO2. FTIR experiments with a of the system.
successive introduction of H2O and CO on reduced Pt-Re/
TiO2 catalyst showed the formation of surface formate 10.9 Current Roles of Supports in
species, which was seen to decompose accompanied by Catalyst Development in Petroleum
the evolution of H2 and CO2 upon reintroduction of H2O. Refining
It was suggested that the role of Re was to stabilize the The petroleum refining industry currently faces heavier
formate species and accelerate the rate of H2 formation crude, stringent regulation of petroleum products, a very
[91]. Spectroscopic data suggest that Re is at least partially high price of crude oil, and spread of the refining industry
in an oxidic state (ReOx) under the reaction conditions over the world as the major issues. Such issues require further
[85–87,91,92]. Another possible role of Re suggested is that improvement of the catalysts and processes, although the
ReOx provides an additional pathway for H2O sorption/ basic schemes of refining technology have stayed essentially
activation, which improves activity [85]. unchanged in recent decades regarding the basic principles,
catalytic species, and processes. More severe operating condi-
10.8.6 Cu-Zn-Al-Type Catalysts tions and multistage processing compensate for insufficient
In the last few years, new Cu-Zn-Al-type catalysts, which functions of the catalysts. Hence, there is room to improve
have higher resistance against hydrothermal conditions the functions of the catalysts.
compared with the conventional Cu-ZnO type, have been The basic guidelines for catalyst development include
reported [105,106]. The effect of DSS accompanied by steam novel combination of catalysts with different functions
purging on conventional Cu-ZnO catalyst was investigated and novel combination of the catalysts and supports. Such
with respect to Cu coordination number, crystallite size, combinations require the development of more detailed
electronic state, number of surface Cu particles by in situ structural concepts of solid catalysts to improve their activity,
XRD, X-ray absorption fine structure (XAFS), and nitrous selectivity, durability, and mechanical strength. The new
oxide (N2O) chemisorption. Reaction tests were performed structural concept of solid catalysts involves
at H2/CO/CO2/H2O = 5:1:1:3 at a GHSV of 2500 h–1. Charac- • Nanoparticles with definite size and crystallization of
terization of the catalyst, which underwent 50 cycles of DSS the catalytic species and support,
treatment with cooling under condensed steam atmosphere • Arrangement of nanoparticles in the nearest and next-
between each cycle, was performed after in situ reduction nearest neighbors,
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244 Petroleum Refining and Natural Gas Processing

• Three dimensional arrangement of catalytic function in against the catalytic species, which is chemically
the real catalyst grain (pellets or cylinders), modified by such a support. This modification can
• Physical access to the nanoparticles, sometimes, but not always strengthen the catalytic
• Chemical interaction among nanoparticles, and functions of the supported species. For example, TiO2
• Molecular transfer and conversion over the series of is reported to be such a support. TiO2 is first found to
active sites distributed on the particle surfaces. very strongly trap the noble metals such as platinum to
In catalytic refining, for the reactions in fluid phase reduce its catalytic activity when they are heat-treated
over solid catalysts, the feed molecules must move from at higher temperatures. A strong metal support interac-
the bulk phase to the grain surface; diffuse into the pore tion such as in this case is not desirable. However, an
on the surface of the particles, which may spread into the adequate temperature of the heat treatment was found
center of the grain; go through particular catalytic reactions to enhance the catalytic activity through favorable
on the active sites; and return to the bulk phase. In such a metal support interaction. Cobalt tetraphenyl porphyrin
series of steps, feed molecules behave in monomolecular or is reported to give radical species when supported on
clustered forms. Hence, the mass transfer of feed molecules TiO2 of large surface area when appropriately heat-
in the liquid and pore to meet the active site on particular treated. Such a combination promotes some catalytic
positions of the molecule is strongly affected by their reactions such as NO decomposition and decomposition
solubility. In addition, the solvolytic reactions of partner of hydrogen peroxide. Such roles of supports suggest
molecules may take place to control the adsorption, desorp- ways to enhance the catalytic activity and to provide
tion, and reactivity of the feed and the products. new functions through interaction of the catalytic spe-
cies and the support. Adequate treatments as well as
10.9.1 Roles of the Catalyst Supports the careful selection of the catalyst and support are
The roles of catalyst supports can be addressed under three essential to develop novel catalysts. Some examples of
main considerations: the catalytic development in the refining technologies
1. Larger effective surface area of the catalytic species: The based on support selections are reviewed below.
catalyst support is most classically expected to provide
the larger effective surface of the catalytic species dis- 10.9.2 Catalyst Supports for HDS
persed on the surface of the support. This role of the Deep HDS has been required to meet the environmental
support is expanded to the conserving of the solid state regulations on gasoline and diesel to achieve less than
of the catalytic species, allowing the smaller pressure 10-ppm sulfur content. The HDS mechanism and catalysts
drop at the flows of the feed and the product and easy have been studied extensively. The problem in deep HDS
separation from the catalytic materials. Thus, the sup- of diesel fuel is to rapidly desulfurize the refractory sulfur
port is expected to have a larger surface area and stron- species such as 4,6-dimethyl dibenzothiophene at tempera-
ger interaction to better disperse the catalytic species. tures below a certain limit where the catalyst deactivation
However, the smaller pores to increase the surface are and cracking of the feed would not occur. The HDS of sulfur
not necessarily favorable because the catalytic species species in diesel fuel is known to occur according to the
may not get into the pores whereas the feed and the following five schemes, shown in Figure 10.27:
products may suffer diffusion limitations to meet the 1. Direct HDS,
catalytic species in such pores or leaving the pores after 2. HG before HDS,
the reaction. Too strong of an interaction between feed 3. Isomerization before HDS,
or product molecules and catalyst surfaces may deac- 4. Demethylation, and
tivate the catalytic species because such an interaction 5. C-S bond scission.
can change the chemical properties of the catalytic Because of steric hindrance due to the two methyl groups
species. at particular positions of 4,6-dimethyl dibenzothiophene,
2. Bifunctional roles of the support: Some supports are direct HDS is strictly inhibited. Hence, the schemes 2–5 are
acidic, for example, while the support and catalytic postulated for HDS of refractory sulfur species. For example,
species possess activity for HG or dehydrogenation in scheme 2, HG of one phenyl group is desired, and for
reactions. In such a case, the feed can be subjected scheme 3, migration of the methyl group on the phenyl ring
first to dehydrogenation, subsequently to acidic isom- is designed. Thus, a byfunctioned catalyst for acidic isom-
erization, and finally to HG. Such a series of catalytic erization and subsequent HDS is utilized. A combination of
reactions proceed successively over the particular acidic zeolite as an acidic catalyst for HDS using CoMoS/
combination of the catalyst and supports. Thus, the Al2O3 is proposed. A problem with this catalyst is the rapid
support is expected to function not only as a carrier of deactivation due to coke formation on the zeolite. The prob-
the catalytic species for a particular reaction but also lem must be overcome by adjusting the reaction conditions
as a catalyst for another reaction. Such a combina- to limit undesired reactions. Weaker acid catalysts do not
tion of the catalyst and support provides bifunctional allow the desired isomerization reactions.
catalysts. Some supports can strongly adsorb the feed A second approach is to enhance the HG of phenyl
or products that are transferred to catalyst surfaces. groups in the presence of H2S at fairly high concentrations.
The adsorption of reactants accelerates the catalytic Acidic support has recently been found to enhance the HG
reaction. The transfer of reactants from the catalyst to activity. Thus, several acidic supports are reported to be
the support is defined as “spillover.” The transfer in the effective for HDS of refractory sulfur species, including Al2O3-
reverse direction is termed “reverse spillover.” SiO2, Al2O3-B2O3, Al2O3-zeolite, TiO2-SiO, and TiO2-Al2O3.
3. Chemical modification for catalytic species: The supports Some acidic supports are highly acidic whereas the acidic
can be acidic/basic, oxidative/reductive, or coordinative reactions of the feed are not wanted. Hence, the direct
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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AST-MNL58-11-0801-010.indd 244 3/12/13 2:15 PM

Chapter 10 n Advances in Catalysts for Refining Processes 245

Direct HDS

S
CH3 CH3 CH3 CH3

Hydrogenation

S
CH3 CH3 CH3 CH3

Isomerization

H3C S CH3 H3C CH3

Demethylation

S
CH3 CH3 27.

C-C bond scission

HDS
S
CH3 CH3 CH3 CH3
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 10.27—Schemes of HDS in diesel fuels.

interaction of the feed and acidic support must be avoided carbon on the alumina support may moderate the acidity
or the acidic site must be restricted to the HDS catalyst. The to control the HG activity of the supported CoMoS. This
present authors proposed an alumina coating of zeolite to approach leads to a better performance of the HDS catalyst
function as such a support. for treating cracked gasoline.
Another important role of an acidic support is to
enhance the desorption of adsorbed H2S on the catalyst 10.9.4 Support of HDM Catalyst
active site. Hence, the catalyst can be active under high H2S Crude currently tends to be heavier and contain higher
partial pressures, which are often brought about by the feed concentrations of metal, nitrogen, and sulfur species. Hence,
of very high sulfur content. extensive HDM is expected to be performed to remove V and
There still remains in deep HDS of highly aromatic feed Ni, which exist as ions in porphyrin complexes in petro-
containing refractory diesel fuel fraction. Catalytic species leum. The roles of the catalyst in HDM are
should overcome the inhibition of aromatic partners for the • Decoagulation of asphaltene structure to allow for the
hydrogenative HDS of the refractory sulfur species. contact of metal ions to the active sites of HDM catalyst
through partial HG, defining the effectiveness of HDM;
10.9.3 Supports for Deep and Selective HDS of • Supplying H2S through HDS of reactive sulfur species;
Gasoline • Eliminating metal ions on the surface of HDM catalyst
Deep HDS of straight-run gasoline is relatively easy because in the form of sulfides; and
gasoline does not contain any refractory sulfur species. Hence, • Trapping and storage of metal sulfide to continue the
milder conditions to achieve the zero-sulfur goal become a HDM process to increase HDM capacity.
research target. In contrast, cracked gasoline, a product from HDM catalyst has been developed to impregnate NiMo
FCC and thermal cracking, contains significant amounts on alumina of large pore and large surface area. The roles of
of olefins and benzenes that increase the octane number. NiMo and alumina can be allocated into 1 and 2 for NiMo
Thus, the issue is to achieve deep HDS without HG of ole- and 3 and 4 for alumina, respectively. Roles of 1 and 2 can be
fins and benzenes, whereas olefins are very reactive for HG. replaced by solvent and recycling H2S to the HDM step as
Hence, the key point is how to suppress the HG of olefins, proved by Shell patent, respectively. The alumina of HDM
keeping the high direct HDS activity. As described in this catalyst has been proven to carry metal sulfide; hence, the
section, the support helps control such an activity. Carbon activity of NiMo is restored while the elimination of metals
supports are supposed to reduce the HG activity. Concern- progresses. It is not clarified yet how metallic species can
ing the acidic function of the support on the HG activity, the move on the alumina surface to form sulfide particles.
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246 Petroleum Refining and Natural Gas Processing

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Catal., Vol. 55, 2006, p. 265. “Sustainable Hydrogen from Bio-Oil—Steam Reforming
[87] Azzam, K.G., Babich, I.V., Seshan, K., and Lefferts, L., “Role of Acetic Acid As a Model Oxygenate,” J. Catal., Vol. 227,
of Re in Pt-Re/TiO2 Catalyst for Water Gas Shift Reaction: A 2004, pp. 101–108.
Mechanistic and Kinetic Study,” Appl. Catal. B, Vol. 80, 2008, [99] Jacobs, G., Graham, U.M., Chenu, E., Patterson, P.M., Dozier,
pp. 129–140. A., and Davis, B.H., “Low-Temperature Water-Gas Shift:
[88] Zhu, X., Hoang, T., Lobban, L.L., and Mallinson, R.G., Impact of Pt Promoter Loading on the Partial Reduction
“Significant Improvement in Activity and Stability of Pt/ of Ceria and Consequences for Catalyst Design,” J. Catal.,
TiO2 Catalyst for Water Gas Shift Reaction Via Controlling Vol. 229, 2005, pp. 499–512.
the Amount of Na Addition,” Catal. Lett., Vol. 129, 2009, [100] Goguet, A., Shekhtman, S.O., Burch, R., Hardcare, C.,
pp. 135–141. Meunier, F.C., and Yablonsky, G.S., “Pulse-Response TAP
[89] Panagiotopoulou, P., and Kondarides, D.I., “Effect of the Studies of the Reverse Water-Gas Shift Reaction over a
Nature of the Support on the Catalytic Performance of Noble Pt/CeO2 Catalyst,” J. Catal., Vol. 237, 2006, pp. 102–110.
Metal Catalysts for the Water-Gas Shift Reaction,” Catal. [101] Choung, S.Y., Ferrandon, M., and Krause, T., “Pt-Re Bimetallic
Today, Vol. 112, 2006, pp. 49–52. Supported on CeO2-ZrO2 Mixed Oxides as Water-Gas Shift
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and Boghosian, S., “Particle Size Effects on the Reducibil- [102] Gorte, R.J., and Zhao, S., “Studies of the Water-Gas Shift
ity of Titanium Dioxide and Its Relation to the Water-Gas Reaction with Ceria-Supported Precious Metals,” Catal.
Shift Activity of Pt/TiO2 Catalysts,” J. Catal., Vol. 240, 2006, Today, Vol. 104, 2005, pp. 18–24.
pp. 114–125. [103] Hilaire, S., Wang, X., Luo, T., Gorte, R.J., and Wagner, J., “A
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“Marked Addition Effect of Re upon the Water Gas Shift Supported Metallic Catalysts,” Appl. Catal. A, Vol. 215, 2001,
Reaction over TiO2 Supported Pt, Pd and Ir Catalysts,” Catal. pp. 271–278.
Comm., Vol. 7, 2006, pp. 91–95. [104] Wang, J.A., Cuan, A., Salamones, J., Nava, N., Castillo, S.,

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
[92] Sato, Y., Soma, Y., Miyao, T., and Naito, S., “The Water-Gas- Moran-Pineda, M., and Rojas, F., “Studies of Sol-Gel TiO2
Shift Reaction over Ir/TiO2 and Ir-Re/TiO2 Catalysts,” Appl. and Pt/TiO2 Catalysts for NO Reduction by CO in an Oxygen-
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Temperature Water Gas Shift Reactions,” Appl. Catal. A, Vol. 303, 2007, Abstract No. 99.
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Vol. 51, 2008, p. 60. Japan Meeting, Nagoya, Japan, 2008, Abstract No. 102.

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11
Natural Gas Conditioning and Processing
Calogero Migliore1

11.1 Introduction 11.2 Properties of Natural Gas

Natural gas is the fastest growing form of energy in the 11.2.1 What Is Natural Gas?
world. Annual global consumption is expected to reach Starting from its origin, it is generally accepted that natu-
160 trillion f3 (4.5 × 1012 m3) by 2020. Natural gas is a more ral gas derives from the microbial degradation of organic
environmental-friendly energy source compared with oil matter that was buried in the sands of what was before
and coal. It is increasingly being utilized for power gen- seashore. Many of the source rocks of significant gas depos-
eration and is already extensively used for industrial and its appear to be associated with the worldwide occurrence
household consumption as well as for the production of of carboniferous coal (roughly 286,000,000 to 360,000,000
advanced petrochemical derivatives. These facts describe years of age) [1].
the importance and perspectives of natural gas as a future In general, where oil and gas occur together, three lay-
major energy commodity, holding the promise of being the ers of fluid exist with water at the bottom, then oil, and gas
energy source of the 21st century. on top. Gravitational and capillary forces largely control
The development of the natural gas industry has been the distribution of these fluids’ accumulation. Typical fluid
very much influenced by the physical characteristics of distributions resulting from the equilibrium of these forces
natural gas. Oil, being a liquid at ambient temperature, can are shown schematically by sectional views of a dome trap
be contained and transported relatively easy using simple in Figures 11.1 and 11.2. Also illustrated in the figures are
and less-expensive technologies; natural gas is more com- the possible modes of occurrence of the natural gas in the
plex and generally more expensive to store and transport reservoir: associated free gas, associated solution gas, and
because of its physical nature, which requires high pres- nonassociated free gas.
sures, very low temperatures, or both. In a reservoir in which crude oil (liquid phase) and
Getting gas to the market has always been problematic natural gas (free gas phase) occur together (Figure 11.1),
and has prevented the development of many fields. Most there is also an associated natural gas in solution with oil.
natural gas industry developments have thus been based on This gas will flow out of the liquid phase once the pressure
indigenous resources. Natural gas was initially traded based drops below the saturation pressure in the reservoir or in
on transmission through pipelines between neighboring the surface at the production facilities.
countries. It was only with the success of the transport trials A reservoir of only natural gas is shown in Figure 11.2.
as liquefied natural gas (LNG) in the 1960s that long-distance The gas in this kind of reservoir is nonassociated gas
trade between nonbordering countries was established. because no crude oil coexists in the reservoir. Depending
Transportation is a major aspect of the gas industry to on the amount of condensable hydrocarbons C3–C5+ pres-
ensure the supply of gas to the users. The main objective ent, these natural gas reservoirs can be divided into three
of a natural gas supply system is to produce gas from an groups: dry gas, wet or rich gas, and retrograde gas or con-
underground field, move it to a processing facility where densate gas reservoirs. In a retrograde or condensate gas
the gas is processed to an acceptable quality, and then move reservoir, initially all hydrocarbons are present in a single
it to customers for its final use. This cannot happen without gas phase in the reservoir, but condensation will occur dur-
there being a continuous link from the producing field to ing pressure depletion.
the consumer of the gas. This involves the natural gas value Natural gas is a compressible fluid. There are many
chain concept. implications of this for the safe and economic supply of gas,
Currently there exist two chains in the gas industry. but the most important is the energy content per volume
One scheme involves a conventional arrangement in which unit. At atmospheric pressure and ambient temperature,
natural gas is transmitted all of the way from the field to natural gas has a very low energy content, whereas oil,
the city gate or consumer facility in high-pressure pipelines. being an incompressible fluid at those conditions, has a high
The other one is the LNG scheme, which involves the liq- energy content. Therefore, oil is transported and stored using
uefaction of the gas, its transportation in bulk carriers, the relatively simple and less-expensive technology; in contrast,
regasification at the point of delivery, and the transporta- natural gas must be transported and stored at high pressure
tion to the final users also through high-pressure pipelines. or in its liquefied form (LNG) to achieve an energy content
This chapter will review the processing facilities that makes the cost of the infrastructure economically viable.
involved in both existing schemes and their contribution Methane is the main constituent of natural gas. The
with respect to the natural gas value chain concept. New remainder may contain various amounts of the higher
proposed gas value chains and other technologies to mon- hydrocarbon gases, such as ethane, propane, butane, and
etize natural gas will be also discussed. pentane, and nonhydrocarbon gases, such as carbon dioxide
1
Repsol Technology, Madrid, Spain
249
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250 Petroleum Refining and Natural Gas Processing

CAP ROCK
Table 11.1—Composition of a Typical
SOLUTION GAS Natural Gas
GAS CAP
Component Vol %
Methane 85.10
Ethane 8.70
OIL Propane 2.90
Butanes 0.90
WATER
Pentanes +
0.15
H2S Trace
CO2 1.75
N2 0.50
Helium None

Figure 11.1—Schematic diagram of an associated gas reservoir. the two most popularly used EOS for natural gas systems—
the Soave-Redlich-Kwong (SRK) and the Peng-Robinson
(CO2), nitrogen, hydrogen sulfide (H2S), and helium. Table (PR) equations.
11.1 shows the composition of a typical natural gas.
Some of the natural gases produced contain acid gases 11.2.2.1 Ideal Gas Law, Real Gas Behavior,
(CO2 and H2S) at levels that require treatment. Gases con- and Compressibility Factor
taining CO2 or H2S are known as sour gases; if they are free The simplest EOS is the ideal gas law. The concept of an
of them, then they are known as sweet gases. CO2 must be ideal gas is a hypothetical approach, but is very useful to
kept below certain limits, normally below 3 % by volume, explain real gas behavior. An ideal gas is the one that follows:
because it can cause corrosion in pipelines in combination • The molecules occupy no volume (the size of molecules
with water. H2S is also highly corrosive and it is toxic. It is zero).
must normally be reduced to approximately 5 mg/m3. • There are no interaction forces between molecules.
• Collisions between molecules are elastic (no energy
11.2.2 Thermodynamic Properties—Equation loss during collision).
of State Following the ideal gas law, the state of a gas is deter-
Thermodynamic properties may be predicted by correlating mined by its pressure, volume, and temperature according
pressure (P), volume (V), and temperature (T). The state to the equation
of matter under a given set of physical conditions follows
physical laws. The mathematic representations of these PV = nRT (11.2)
laws are known as equations of state (EOS), which corre- where P and T are the absolute pressure and temperature
late PVT data on a mole basis as follows: of the gas, n is the number of moles, and V is the volume
Φ(PVT) = 0 (11.1) occupied by the gas. R is the universal gas constant.
At low pressure (e.g., pressure up to ≈ 60 psia, ≈ 400
There are many EOS available today that have been
kPa), the ideal gas law is moderately accurate for most
developed over the years. In this section, only the two most
gases. However, generally speaking, real gases do not
basic available EOS will be mentioned—the ideal gas law
exhibit ideal behavior. They deviate from ideal behavior
and the real gas equation using compressibility factor—and
because of the following reasons:
• Molecules occupy a finite volume.
CAP ROCK
• There exist intermolecular forces exerted between
GAS CAP molecules.
• Molecular collisions between molecules are not elastic.
The compressibility factor Z allows correcting for
nonideal gas behavior. It is a very useful thermodynamic
property to account for a real gas approach. The simplest
form of an equation of state using the correction factor Z
is the following:
WATER
PV = nZRT (11.3)

Therefore, in this case, Z is the ratio of the volume occupied

by the real gas to the volume occupied if it were ideal. Z var-
ies with pressure, temperature, and gas composition.

11.2.2.2 Cubic EOS

Cubic EOS are the simplest expressions that can, in prin-
Figure 11.2—Schematic diagram of a nonassociated gas ciple, represent the vapor- and liquid-phase volumetric
reservoir. behavior of pure fluids. The most widely used for natural
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Chapter 11 n Natural Gas Conditioning and Processing 251

gas are the SRK (11.4) and the PR (11.5) equations. Both
equations were designed specifically to yield reasonable Table 11.2—HHV of the Components
vapor pressures to perform satisfactory for vapor/liquid of Natural Gas
equilibrium calculations. Component HHV (MJ/Sm3)
Methane 37.7
RT αa (11.4)
P= − Ethane 66.1
v − b v ( v + b)

Propane 93.9
RT αa (11.5) Butanes 121.6
P= −
v − b v ( v + b) + b ( v − b) Pentanes +
>149.4

where α, a, and b are system parameters. Parameters a and H 2S 23.8
b are determined from the critical temperature (Tc) and CO2 0
critical pressure (Pc). Parameter α is determined from a N2 0
correlation based on experimental data that use a constant
Helium 0
called the Pitzer acentric factor (ω). Pitzer’s acentric factor
is a measure of the configuration and sphericity of the mol-
ecule, a measure of the deformity of the molecule. the carbon monoxide (CO) production because the amount
For single-phase hydrocarbon gas systems at a pres- of air remains the same in the burner but the requirement
sure above 10 bar, the SRK and PR equations show similar for complete combustion has been increased. Conversely, a
performance, although PR is generally better in predicting reduction in the WI will lead to a loss of heat service and
cryogenic systems. flame instability.
For mixtures, both equations introduce the use of The WI and impurity levels define the suitability of a
binary interaction parameters (kij). These are empirical natural gas for a particular market, and more specifically to
factors that represent the interaction between a pair of a particular appliance.
dislike molecules. The interaction parameters for SRK and
PR are unlikely to be the same because of their empirical 11.3 Natural Gas Conditioning
character. 11.3.1 Introduction
Natural gas from the reservoir normally contains water and
11.2.3 Heating Value various contaminants such as nitrogen (N2), CO2, H2S, and
The heating value of natural gas is the energy released as other sulfur compounds such as carbonyl sulfide (COS)
heat after the complete combustion of a mass unit of gas. and mercaptans (RSH), aromatics, mercury, and sometimes
It is a prime characteristic of natural gas because gas com- helium. Purification processes for natural gas are hence of
bustion is the main final use of this fuel, either to provide primary importance.
heat (primary energy) or power, when used in gas engines. The presence of contaminants can result in damage to
It is also a key quality factor in gas trading. Methane, the process facilities or failure to meet sale or environmental
main component of natural gas, has a heating value of specifications; therefore, they have to be removed to a cer-
37.71 MJ/m3 at 15°C and 1 atm; this value is obtained by tain degree. The current trend of applying more severe emis-
cooling down the combustion products to 15°C. If water sion and environmental standards requires gas streams to
remains as vapor, then the energy recovered is known as the be purified to even more stringent levels. In addition, lower
net heating value or lower heating value (LHV). If water is limits can also be set for plant operation reasons, especially
condensed, the recovered energy is known as the gross heat- in liquefaction plants: water, CO2, and aromatics can freeze
ing value or higher heating value (HHV). Table 11.2 shows on heat exchanger surfaces, reducing efficiency and causing
the high heating value of the components of natural gas. blockages; as far as mercury is concerned, it attacks alu-
minum, the main construction material for cryogenic heat
exchangers. Typical specifications for impurities contained
11.2.4 Wobbe Index in the liquefaction section feed gas are listed in Table 11.3.
The wobbe index (WI) or wobbe number gives a measure of
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In high-pressure pipelines, water is removed before com-

the relative heat input into a burner at a fixed gas pressure pression to prevent corrosion, freeze-ups, and hydrate
of any fuel gas. It is defined as

WI =
HHV
(11.6) Table 11.3—Typical Impurity Specifications
d in Gas to Liquefaction Section
where d is the relative density of gas (air = 1). Component Limit (max)
The WI is the combination of the heat input and the Water 1 ppmv
flow of gas into a burner. The heat input is directly pro- Total sulfur 30 mg/SCM
portional to the heating value, and the flow of gas into a
H2S 3–5 ppmv
burner is inversely proportional to the square root of the
relative density. CO2 50 ppmv
The WI is a measure of the burning character of a Mercury 0.01 mg/SCM
natural gas. WI is important for calculating the amount of Benzene 1 ppmv
air to be drawn into a simple burner such as those used in
Pentenes and heavier 0.1 mol %
a typical domestic appliance. Raising the WI will increase
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252 Petroleum Refining and Natural Gas Processing

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 11.3—Amine unit at the YPF La Plata Refinery (Argentina). Source: Picture courtesy of YPF.

formation; dew point control processes are also frequently Afterward, the resultant “rich” amine solution is fed to the
used to avoid condensate formation during transportation. regenerator and regenerated by reboiling. The acid gas, or
The main processes for natural gas treatment are dis- off-gas, is sent to a sulfur recovery unit if the volumes of
cussed in the next sections. sulfur that can be recovered are sufficiently large to justify
the investment or the environmental restrictions require
11.3.2 Acid Gas Removal (Gas Sweetening) high levels of sulfur recovery; if not, the off gases are just
Acid gases (CO2 and H2S) can be removed from feed gas flared or incinerated. The cooled regenerated amine solu-
by different treatment technologies such as chemical and tion, or “lean” amine, is recirculated back to the head of the
physical absorption processes, amongst others. Examples absorber column.
of chemical absorption are the conventional or activated Some operating conditions and other considerations to
amine process and the hot potassium carbonate process; be taken into account in an amine unit are
examples of physical absorption are the proprietary solvent • Reboiler duty/temperature constraint because of sol-
processes such as Sulfinol™2 and Selexol™3. vent degradation.
The acid gas treatment unit is also referred to as acid gas • Absorber conditions: temperature from 35°C to 50°C
removal unit (AGRU) or sweetening unit because the resulting and pressure from 35 to 205 bar (3500 to 20,500 kPa).
product no longer has the sour, foul odors of RSH and H2S. • Lean amine temperature from 20°C to 55°C to be opti-
mized to increase solvent selectivity.
11.3.2.1 Amine Processes • Regenerator conditions: temperature ranges from
Amine processes are very common in refineries, petro- 115°C to 130°C (bottom) and pressure from 1.4 to 2.0
chemical plants, and natural gas processing plants (Figures bar (140 to 200 kPa).
11.3 and 11.4). The simplified process flow diagram (Figure There are many different amines used for gas sweetening.
11.5) illustrates the major equipment in an amine treat- • Monoethanolamine (MEA)
ment process. The raw sour gas is fed to the bottom of an • Diethanolamine (DEA)
absorber equipped with structured or random packing or • Methyldiethanolamine (MDEA)
trays. The gas is sweetened by the amine solution in coun- • Diisopropylamine (DIPA)
tercurrent flow. The solution from the absorber is heated • Diglycolamine (DGA)
up against regenerated solution directly or after flashing. • High-load DEA (activated) and formulated MDEA
Selection of a particular amine process depends on feed
2
Sulfinol™ belongs to Shell Global Solutions International BV,
gas composition and product gas specifications and takes
The Hague, The Netherlands. into account the specific characteristics of each amine. For
3
Selexol™ belongs to Dow Chemical Company. The Selexol tech- instance, CO2 and H2S selectivity is very dependent on the
nology is currently owned by Union Carbide Corporation. selected amine: primary and secondary amines (e.g., MEA,
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Chapter 11 n Natural Gas Conditioning and Processing 253

Figure 11.4—Amine unit at YPF La Plata Refinery (Argentina). Source: Picture courtesy of YPF.

DEA, and DIPA) react directly with H2S and CO2; tertiary the process. It depends on amine concentration, which is
amines, of which the most used is MDEA, is more selective usually limited by corrosion considerations. Thus, MEA
to H2S than CO2. (a primary amine) solution is limited to 15–20 wt % whereas
The acid gas removal capacity of the circulating solu- for DEA (a secondary amine), concentration is limited to
tion, or solvent strength, is another critical parameter of 30 wt %; MDEA can operate at much higher concentrations

Figure 11.5—Typical amine process configuration.

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254 Petroleum Refining and Natural Gas Processing

such as 50 wt % with low corrosion potential. Considerable The Sulfinol process has been used in most LNG plants
additional treating capacity is available with the formulated where Shell has been involved. Over 200 Sulfinol units have
MDEA solvents using the same concentration, 50 wt %. been licensed worldwide, including natural gas, synthesis
MDEA-based solvents are currently the most used in gas, and refinery gas treatment. The solvent is a mixture of
the gas industry. They have received a great deal of atten- Sulfolane and DIPA, Sulfinol D. Another option is Sulfinol
tion because of MDEA’s selective reaction with H2S in the M, which uses MDEA instead of DIPA to minimize hydrocar-
presence of CO2 (preferential removal of H2S from a sour bon absorption with the acid gas. The addition of Sulfolane
gas stream while rejecting or delaying the recovery of most increases the physical solubility of H2S, CO2, and organic
of the accompanying CO2 until a subsequent processing sulfur compounds in the solvent. Approximately 80 % of the
step). Thus, the contact time between the solvent (MDEA) RSH in the sour gas stream are removed at this step; they
and sour gas is designed to allow removal of the H2S up are then further reduced in the molecular sieve unit.
to the required degree and at the same time to minimize The Selexol process uses a physical solvent made of a
CO2 coabsorption. Increased selectivity for H2S over CO2 mixture of dimethyl ethers of polyethylene glycol to remove
expands the regeneration capacity of the amine unit, acid gases from synthetic or natural gas. The process sol-
reduces the energy required for the process, and improves vent is regenerated either thermally, by flashing, or by gas
the H2S quality of the acid gas. stripping. The Selexol process is ideally suited for the selec-
The selectivity of MDEA and related solvents can be tive removal of H2S and other sulfur compounds or for the
influenced by bulk removal of CO2.
• Contact temperature: Colder processing (less than 32°C) A common feature of physical solvent processes such
or hotter processing (greater than 50°C) results in as Sulfinol and Selexol is hydrocarbon coabsorption, which
improved selectivity. is usually a disadvantage because of
• Contact pressure: lower pressure improves selectivity. • The loss of valuable hydrocarbons into the acid gas
• Feed gas CO2/H2S ratio: higher ratios of CO2 to H2S (less sales)
favor selectivity. • Contamination potential of the acid gas stream to the
• Total acid gas load. sulfur recovery unit by formation of COS, carbon disul-
• Location of lean amine feed point on the absorber fide (CS2), and C (carbon or soot) [3].
tower. Membrane separation is based on the principle of
MDEA-based solvents have numerous advantages over selective gas permeation. When a gas mixture is introduced
primary and secondary amines. to a membrane system, gas components dissolve into the
• Selective removal of H2S from the gas stream while membrane material and diffuse through it. Solubility and
kinetically limiting CO2 absorption. diffusivity are different for each gas component. CO2, water
• Increase in sulfur plant efficiency and capacity because vapor, and H2S are easily permeable gas components,
of the H2S-enriched gas feed. whereas methane, ethane, and other hydrocarbons perme-
• Less degradation. Unlike MEA, DEA, or DGA, MDEA ate very slowly. This kind of process is typically applied for
does not form amine CO2 degradation products that CO2 bulk removal; for example, in natural gas treatment to
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

enhance corrosion at elevated temperatures in the meet pipeline specifications and for production of a CO2-
regenerator. rich stream for enhanced oil recovery (EOR) injection.
• Less corrosion.
• Lower amine circulation rate and pumping power. Acid 11.3.3.1 Adsorption Processes
gas pickup of up to 0.5 mole/mole MDEA is available Pressure swing adsorption (PSA) is based on the cyclic
without the need for costly metallurgy upgrades. physical adsorption of the contaminant at a high pressure
Finally, the desirable characteristics of basic MDEA followed by desorption at low pressure. Typical applica-
have been extended by various manufacturers with the tions of the PSA process are the separation of CO2 from
addition of chemical enhancers to create high-performance methane for upgrading of landfill gas, upgrading of biogas
formulated MDEA products [2]. An example of this is Dow from digesters, and production of natural gas from poor-
Chemical’s solvent Ucarsol®4, which has very high versatil- quality reserves. Molecular sieves efficiently remove low
ity and selectivity to remove CO2 and H2S. Some benefits of concentrations of polar or polarizable contaminants such
using a formulated solvent are smaller and more efficient as H2O, methanol, H2S, CO2, COS, RSH, sulfides, ammo-
plants, reduced energy consumption, lower capital cost, nia, aromatics, and mercury down to trace concentrations.
and lower contaminant levels in treated gas. Extractive distillation can be used to separate H2S from CO2
but has a high energy cost [3].
11.3.3 Other Acid Gas-Treating Processes
Hot potassium carbonate is used to remove CO2 from a
mixture of gases by absorption and then stripping the 11.3.3.2 Sulfur Recovery and Tail Gas
solution by pressure reduction without additional heating. Treating
The flow scheme of the hot potassium carbonate process Sulfur recovery is used to reduce the sulfur emissions fol-
shares some features with amine processes; however, in the lowing legislation. The Claus sulfur recovery process con-
hot potassium carbonate system, the gas-liquid contactor sists of two steps:
operates at high temperature, which saves a considerable 1. Thermal step: The H2S is first partially oxidized at high
amount of heat exchange in the process. temperature (1000–1400ºC) with air, forming SO2.
Afterward, the Claus reaction takes place (2H2S + SO2
to 3/XSx + 2H2O), producing elemental sulfur, with
4
Ucarsol® belongs to The Dow Chemical Company, TX. 60–70 % of the total sulfur being produced in this step.
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Chapter 11 n Natural Gas Conditioning and Processing 255

2. Catalytic step: The remaining H2S and SO2 go to the MEG is injected not to “dehydrate” the gas (see Dehydration
catalytic section at lower temperatures (200–350ºC) for by Absorption) but rather to improve the water separation
further conversion to elemental sulfur. and prevent hydrates from forming.
A tail gas unit manages the tail gas from the Claus pro-
cess with the remaining sulfur compounds. There are three 11.3.3.3.3 Dehydration by Absorption
main options for tail gas treating: The main use of this dehydration process is to reach water
1. Additional Claus catalytic process dew point specification to avoid water condensation in
2. Recovery of the sulfur compounds and its recycle to pipelines. The hydrocarbon dew point of the gas is related
the Claus unit to its natural gas liquids (NGL) content, so it remains the
3. Tail gas H2S selective oxidation to sulfur same as for the feed gas.
Glycols are typically used for applications in which
11.3.3.3 Dehydration water dew point depressions on the order of 15–49°C are
11.3.3.3.1 Overview required. DEG, triethylene glycol (TEG), and tetraethylene
The main reason for removing water vapor from natural glycol (TREG) are all used as liquid desiccants. TEG is the
gas streams is that it becomes liquid or solid under low- most common for natural gas.
temperature and high-pressure conditions. Thus, liquid water In general terms, the unit configuration consists of a
in natural gas pipelines causes various flow problems such as simple absorber/regenerator system (see Figure 11.6). The
corrosion, slug flow, or hydrate formation, which results in gas enters at the bottom of the glycol absorber equipped
plugging or flow restrictions. Water is also removed to meet with structured packing or trays. As the gas rises, the
sales gas specifications. In cryogenic facilities, water can water is removed (absorbed) by the decreasing TEG
freeze and produce blockages. All of these problems reduce the concentration. Concentration of the lean glycol enter-
availability and efficiency of pipelines and process equipment. ing at the top of the absorber is the main variable that
There are some cases when gas pipelines need to be determines the water dew point specification that can
operated with the presence of liquid water although the be reached and therefore the efficiency of the process.
temperature is below the hydrate formation point. In those The rich glycol that leaves the absorber is sent to a flash
cases, hydrate inhibitors are necessary; alcohols or glycols drum and then to a regeneration section. The lean glycol
such as methanol, diethylene glycol (DEG), or mono- leaving the regeneration section is finally returned to
ethylene glycol (MEG) are typically injected to depress the absorber closing the loop. Like the amine process, a
hydrate and freezing temperatures. The three main types lean-rich heat exchanger is used to heat up the rich glycol
of processes to dehydrate natural gas are condensation, solution to conserve energy.
absorption, and adsorption.
11.3.3.3.4 Dehydration by Adsorption
11.3.3.3.2 Dehydration by Condensation Dehydration by adsorption is used to obtain very low water
Dehydration by condensation consists in cooling natural content (0.1 ppm or less), levels required in NGL extraction
gas and separating water as a condensate. In this process, and LNG production plants. It is based on solid desiccant
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 11.6—TEG dehydration unit.

AST-MNL58-11-0801-011.indd 255 3/12/13 2:17 PM

256 Petroleum Refining and Natural Gas Processing

11.3.3.4 Sulfur Compound Removal

Table 11.4—Typical Adsorbents for A primary contaminant found in most raw natural gas
Dehydration [4] streams is sulfur, in the form of H2S, elemental sulfur and
Desiccant Outlet Water Dew Point (°C) often in various other organic forms (RSH, COS, etc.).
Alumina –73 Sulfur compounds are known poisons for most gas and
refinery processes, even when present at very low levels
Silica gel –60
(often below detection levels at many facilities), and are
Molecular sieves Less than –100 significant contributors to atmospheric pollution.
As a general rule, when the integrity, operation, and
materials called adsorbents. The most common adsorbents maintenance of the facility are not compromised, it is rec-
are alumina, silica gels, and molecular sieves. Table 11.4 ommendable, in terms of cost and contaminant removal
shows the dew point achievable with each of them. effectiveness, to treat the most concentrated stream.
The dehydration process based on adsorption consists Thus, the heaviest sulfur components are usually removed
of several vessels filled with adsorbent (adsorption beds). from the heaviest streams of the NGL fractionation process.
In LNG and NGL extraction plants, each bed is commonly On the other hand, lighter sulfur components, such as H2S,
made up of four layers of material: inert ballast balls, a are removed from the gas streams [5,6].
guard layer, a water adsorption layer, and inert ballast balls The molecular sieves are commonly used as a dry
again. Table 11.5 shows the material commonly used in regenerative process to treat propane or butane streams
each of the different layers. and can also be used for treatment of mixed LPG streams.
The most used desiccant for the water adsorption With the appropriate type of sieve material, the product
layer is zeolite 4A, which is used in different sizes and can be treated to meet water content, volatile sulfur, and
shapes. The guard layer of silica gel or alumina adsorbs any corrosion (copper strip test) specifications in one single
entrained water liquid droplets and solvent traces. The inert process.
ballast balls prevent desiccant movement and aid in gas dis-
tribution [4]. A typical life cycle considered for adsorbent 11.3.3.5 Mercury Removal
materials is 2–4 years. Another impurity that can be present in a natural gas
Figure 11.7 shows a typical water adsorption unit stream is mercury, primarily in elementary form and in
composed of three vessels, two of them operating in very small amounts. Chlorides and other species can also
water adsorption mode whereas the other one is being be present.
regenerated. Once a bed has been in adsorption mode for Mercury combines with aluminum to form a
approximately 16 h, it switches to regeneration mode for mercury-aluminum amalgam. When the amalgam is
approximately 8 h. The regeneration is composed of two exposed to air, the aluminum is oxidized, and the oxide
main stages: flakes away. Mercury is again available to form amalgam
1. Heating step (up to 260–280°C): The regeneration gas and the process is repeated again and again. A small
flow is normally approximately 5–15 % of the process amount of mercury can “eat through” a large amount of
flow and can be heated by a dedicated heat source or aluminum over time. For this reason, and considering
by integrating the dehydration unit with another unit that aluminum is one of the construction materials used
of the plant. in some of the main pieces of equipment in a LNG facil-
2. Cooling step: Once the bed has been regenerated, then ity, mercury must be removed to levels below 0.01 mg/Sm3
it is cooled down to normal adsorption temperature by before entering the liquefaction train.
the regeneration gas (without heating). The mercury removal unit is present in all liquefac-
In liquefaction and NGL extraction plants, the dehy- tion facilities regardless if the contaminant has been iden-
dration unit is placed downstream of the AGRU because tified in the inlet gas. This unit can be placed before the
sweet natural gas from the AGRU absorber is always satu- acid gas treatment unit or after the dehydration unit. It
rated with water. Typical process conditions of the dehydra- typically consists of a bed of sulfur-impregnated activated
tion unit in these types of plants are shown in Table 11.6. carbon.
The source and destination of the regeneration gas This is a nonregenerative process, so at the end of the
can vary depending on the end flash gas (EFG)/boil-off gas life cycle, which could be as long as 10 years depending
(BOG) flow rates, the impurities present in the feed gas, and on mercury content of the gas, the spent carbon must be
the fuel gas system configuration. Typically, the regenera- disposed [7].
tion gas is sweet dry gas and is sent to the fuel gas system.

11.3.3.6 Inert Gas Removal

Table 11.5—Typical Molecular Sieve Natural gas usually contains inert gases such as N2 or
Bed Configuration helium in variable amounts depending on the gas field.
Layer Material Strictly speaking, these gases are not contaminants because
they do not produce any undesirable effect for natural gas
Inert ballast balls Alumina, mullite, or ceramic
processing. However, their presence in natural gas is a
Guard layer Silica gel or alumina problem because it increases the size of gas compression
Zeolite 4A—large size facilities, pipelines, and processing plants. Furthermore,
Water adsorption layer inert gas content must very often be adjusted to meet sales
Zeolite 4A—small size
gas specifications, such as HHV and inert content. Hence,
Inert ballast balls Alumina, mullite, or ceramic
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

simple economic/commercial reasons are involved in the

AST-MNL58-11-0801-011.indd 256 3/12/13 2:17 PM

Chapter 11 n Natural Gas Conditioning and Processing 257

FORVHG

Figure 11.7—Typical three-bed dehydration unit.

decision to remove inerts; on the other hand, natural gas is degree of liquid recovery has a deep impact on process
also the primary market source for helium [8]. selection, complexity, and cost of the processing facility.
These gases are separated from natural gas, when The NGL extracted from natural gas can be further
necessary, via N2 rejection units or helium recovery units. fractionated to make commercial products such as ethane,
Sometimes, a simple end flash can achieve the specifica- propane, butane, and gasoline. The degree of fractionation
tion, but when feed gas composition is rich in N2, stripping is dependent on the market and geography.
or cryogenic distillation technologies will be necessary. The
N2-rich stream separated from the main stream can then be
11.4.2 NGL Extraction [9–11]
used as fuel gas, flared, or sent back upstream for injection
11.4.2.1 Dew Point Control
to maintain field pressure and EOR.
Dew point is defined as the temperature at which vapor
begins to condense. When gas is transported in pipelines,
11.4 NGL Extraction and Fractionation consideration must be given to the control of the formation
11.4.1 Introduction of hydrocarbon liquids in the system. Liquid condensa-
The term NGL applies to liquids recovered from natural tion is a problem for gas metering, pressure drop, and safe
gas and as such refers to hydrocarbon components heavier operation and can cause liquid slugging.
than methane contained in natural gas. The term liquefied To prevent formation of liquids, it is necessary to
petroleum gases (LPG) describes hydrocarbon mixtures in control the hydrocarbon dew point below the pipeline
which the main components are propane and iso- and nor- operating conditions with the desired safety margin for the
mal butane (see Figure 11.8). operation. Operating conditions are usually fixed by design
The NGL extraction from natural gas streams can and environmental considerations, so in practice, single-
range from ethane and heavier hydrocarbon extraction phase flow can only be assured by removing the heaviest
to pentanes and heavier component removal. The desired hydrocarbons in the gas. There are different ways to do it.

11.4.2.2 Low-Temperature Separation
Table 11.6—Typical Conditions of Feed Gas Low-temperature separation (LTS) can be achieved using
to a Dehydration Unit Joule-Thompson (J-T) autorefrigeration or mechanical
refrigeration.
Conditions
If sufficient pressure is available, the cooling required
Temperature (°C) 30–55 for removal of hydrocarbon liquids is achieved through
Pressure (bar) 40–75 a sudden adiabatic gas expansion (J-T expansion or free
Molecular weight (kg/kmol) 17.5–19 expansion) so that heavier hydrocarbons and other con-
densables condensate. The performance of J-T units are
Water (mol %) 0.1–0.3
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

very much dependent on the condition of the incoming raw

AST-MNL58-11-0801-011.indd 257 3/12/13 2:17 PM

258 Petroleum Refining and Natural Gas Processing

LNG
METHANE

ETHANE

NATURAL GAS
Ex-well PROPANE LPG NGL
BUTANES

PENTANES and heavier fractions

also referred to as:
C5+
Pentanes plus
Natural gasoline
Condensate

Nonhydrocarbon constituents
(e.g., water, CO2, H2S, mercury, etc.)

Figure 11.8—Natural gas constituents.

gas streams because they use excess pressure energy of the lighter hydrocarbon products such as ethane and propane.
raw gas stream to autorefrigerate the gas. More particu- These processes have the advantage that the absorber can
larly, the temperature drop is affected by the gas composi- operate at essentially feed gas pressure with minimal pres-
tion, flow rate, and pressure of the feed gas. sure loss, but they require large process equipment and
In other cases, inlet pressure is not high enough to have high energy requirements. Therefore, they are usually
allow a LTS system. An alternative option is to utilize a less attractive than LTS systems.
mechanical refrigeration system to remove heavy hydrocar- The control of water and hydrocarbon dew points of a
bon components. Mechanical refrigeration consists in cool- sales gas can be achieved by the addition of a solvent, such
ing the gas stream to the specified temperature by means of as methanol, glycol, or other proprietary solvents (which
an independent refrigeration cycle (e.g., a propane cycle). improves the solubility of hydrocarbons). This solvent
Liquid is again separated in a cold separator. absorption process is often combined with J-T expansion.
If the gas stream contains water, this process requires The adsorption process, sometimes referred to as
a previous dehydration unit or glycol injection to avoid “short cycle adsorption process,” uses dry desiccant beds
hydrate formation. (e.g., silica gel) to attract or adsorb hydrocarbons and
A new technology called TwisterTM5 was recently proposed, water. Water is the most strongly attracted compound,
which combines expansion, cyclonic liquid/gas separation, and whereas heavy hydrocarbons are attracted more strongly
recompression for dew point control and NGL extraction (C3+). than the lighter ones.
TwisterTM is a compact tubular device that works as a LTS
process with thermodynamics similar to a turboexpander,
11.4.2.4 Ethane and Propane Recovery
causing a temperature drop by transforming pressure to
Dew point control processes are used for applications in
supersonic velocity. The condensed hydrocarbons are sepa-
which moderate propane recoveries are desired. To achieve
rated via centrifugal forces caused by the induced swirl of
higher propane recoveries, ethane recovery, or both, cryogenic
the gas through the device. Afterward, the gas goes through a
temperatures are required. Generally speaking, the natural
diffuser where part of the pressure drop is recovered.
gas industry considers cryogenic processes as those that oper-
ate below –50°F (approximately –45°C). There are different
11.4.2.3 Noncooling Processes methods to reach high ethane recovery levels: J-T expansion,
Noncooling processes have not typically been the preferred turboexpander extraction, and mechanical refrigeration.
option since the development of turboexpander processes,
but they still are considered because they may provide an
optimal solution in certain applications. 11.4.2.4.1 J-T Expansion
The lean oil absorption process is the physical process The J-T effect consists of cooling down the gas by its expan-
in which a vapor molecule of a lighter hydrocarbon compo- sion across a J-T valve. With large pressure drop across the
nent dissolves into a heavier hydrocarbon liquid (nonane, J-V valve, cryogenic temperatures can be achieved, which
decane, and heavier) so that it is separated from the gas results in high extraction efficiencies. To effectively use the
stream. The process can be operated at ambient tempera- J-T effect, inlet gas must be at a high pressure; if not, then
tures if only separation of the heavier NGL products is compression is required.
desired. A refrigerated system enhances the recovery of When the feed gas pressure is not high enough or the
gas is rich in liquefiable hydrocarbons, mechanical refrig-
eration can be added to the J-T process to improve recovery
5
Twister™ Supersonic Separator belongs to Twister BV, Einstein- efficiency. An advantage of the refrigerated J-T process is
laan 10 2289 CC Rijswijk (ZH), The Netherlands.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
that lower feed pressures are required.
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Chapter 11 n Natural Gas Conditioning and Processing 259

The J-T process, either refrigerated or nonrefrigerated, LNG unit, the quality and condition of the feed gas, the
offers a simple and flexible option for moderate ethane required level of NGL recovery, and plot plan area con-
recovery. It is usually applied to reduced gas flow rates in siderations.
which some inefficiency can be tolerated, allowing for the Hydrocarbon extraction schemes can be divided into
reduction of capital and operating costs. two main categories: an NGL extraction unit located in an
independent front-end configuration with its own refrigera-
11.4.2.4.2 Turboexpander Extraction tion system or an NGL unit integrated with the liquefaction
The process that dominates ethane recovery applications is unit. Additionally, an intermediate case can be considered
the turboexpander process. A turboexpander, also referred in which the NGL extraction unit is integrated with the
to as an expansion turbine or expander, is a centrifugal or precooling section, which provides cold for partial conden-
axial flow turbine that extracts work from a high-pressure sation and separation. The NGL recovery varies according
gas stream. From a thermodynamic point of view, the to its position in the process.
expansion across a J-T valve follows an isenthalpic path, The integrated process is very efficient, but it uses the
whereas the ideal expansion through a rotating machine LNG refrigeration power block to extract the NGL and,
to produce mechanical energy follows an isentropic path consequently, production of LNG is reduced. The noninte-
(the enthalpy of the fluid decreases). This leads to a larger grated NGL extraction process uses an independent refrig-
temperature drop than that achieved through a valve for eration system and then recompresses the gas stream for
the same pressure drop. Hence, turboexpander processes efficient liquefaction. It can achieve higher recovery values
allow higher recoveries and efficiencies than J-T valves. than the integrated configuration, but it is less efficient.
The work recovered from the gas stream by the expander
is typically used for driving a compressor. Other pos- 11.4.3 NGL Fractionation
sible options are expander-pump and expander-generator The bottom liquid stream from the NGL recovery unit may
configurations [12]. be sold as a mixed product. This is common for small, iso-
The turboexpander process has been applied to a wide lated plants where there exists insufficient local demand.
range of process conditions for ethane and propane recov- The mixed product is transported by truck, rail, barge, or
ery projects. With the conventional turboexpander process pipeline to a central location for further processing. Often it
configuration, the ethane recovery is limited to approxi- is more economical to fractionate the liquid into its various
mately 80 %; additional process integration as the residue components, which have a market value as pure products.
recycle system is required to recover beyond this level. This The process of separating an NGL stream into its com-
system provides more refrigeration to the process, so it can ponents is called fractionation. At the fractionation unit,
be used for very high ethane recoveries (only limited by the liquids will be separated into commercial-quality products
quantity of power provided). and then delivered to the market by tankers (exports) or
To improve the performance of conventional expander tank trucks (domestic consumption).
systems, new processes have been developed. Examples are NGLs are fractionated by a series of distillation towers.
the gas subcooled process (GSP) [13] and the cold residue Fractionation takes advantage of the difference in boiling
recycle (CRR) process [14]. points of the various NGL products. As the temperature
of the NGL stream is increased, the lightest (lowest boil-
11.4.2.5 Particularities of NGL Recovery in ing point) NGL product boils off the top of the tower, is
Liquefaction Plants [15,16] condensed into an almost pure liquid, and is then sent to
Although NGL recovery processes are widely used in many storage. The heavier liquid mixture at the bottom of the
gas processing plants, different configurations of the NGL first tower is routed to the second tower where the process
recovery units within the liquefaction plant are reviewed is repeated and a different NGL product is separated and
below because of the importance of LNG in the global gas stored. This process is repeated until the NGLs have been
market. separated into their components.
The requirements to remove NGLs in an LNG plant can Fractionators are usually named for the overhead or
be based in one or more of the following reasons [17]: top product. Therefore, a de-ethanizer implies that the top
• To adjust the natural gas quality (heating value) product is mainly ethane; a depropanizer indicates that the
• Commercial interest of NGLs as a separate product top product is propane, etc. (see Figure 11.9).
• To prevent freezing up of heavy components in the
cryogenic section of the liquefaction process 11.4.3.1 Fractionation Operation --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

• To obtain refrigerant makeup for the liquefaction process The operation takes place in a vertical column where vapor
The level of NGL extraction from natural gas is some- and liquid mixtures flow countercurrent and are brought
what discretionary. Safety issues dictate the minimum into repeated contact. During each contact, part of the liq-
extraction level, whereas a balance between technology and uid vaporizes and part of the vapor condenses. The contact
the relative market value of the NGLs determines the maxi- between liquid and vapor takes place in the internals of the
mum extraction level. column that can be trays or packing.
As the vapor rises through the column, it becomes
enriched in the lighter or lower boiling components (recti-
11.4.2.6 Location of the NGL Extraction fication section). Conversely, the downward flowing liquid
Unit in LNG Plants [18,19] becomes richer in heavier, higher boiling components
There are various options for locating the NGL extrac- (stripping section).
tion unit within a liquefaction plant. The selected posi- The liquid mixture that is to be processed is known
tion will depend on the level of integration with the as the feed, which is introduced usually somewhere near
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260 Petroleum Refining and Natural Gas Processing

Figure 11.9—NGL fractionation.

the middle of the column. The feed section divides the 11.4.3.2 Transmission Pipeline (High-Pressure
column into a top (enriching or rectification) section and Pipeline)
a bottom (stripping) section. The feed flows down the The transmission pipeline system ensures an uninterrupted
column where it is collected at the bottom in the reboiler. supply of gas at the desired flow rate and pressure from
Heat is supplied to the reboiler to generate vapor. The the point of production to the delivery point. The delivery
vapor raised in the reboiler is reintroduced into the unit point is often a city gate, but it can also be a large-volume
at the bottom of the column. The liquid removed from user, such as a power plant. The high-pressure pipeline is
the reboiler is known as the bottom product. The vapor a very convenient method of transporting gas; however, the
moves up in the column, and as it exits the top of the unit, pipelines are not flexible because they tie the gas source to
a condenser cools it. a particular destination. If the pipeline has to be shut down,
The condensed liquid is stored in a holding vessel the gas source often has to be shut down as well.
known as the reflux drum (accumulator). Some of this The use of pipelines has been the most important fac-
liquid is recycled back to the top of the column and is tor in promoting the growth of the natural gas industry
called the reflux. The condensed liquid that is removed throughout the world. More than 90 % of the natural gas
from the system is known as the distillate or overhead consumed in the world is delivered through pipes. Even
product (in some cases, the overhead product is a vapor). with LNG, once it is regasified, it can only be delivered
To avoid reducing the operating pressure of the fraction- through a pipeline system.
ator (which would require further recompression), the In gas pipelines, compression (or formation pressure,
fractionation process should be carried out with minimal or both) drives the flow. Flow resistance is primarily due
loss of pressure. to pipe friction. The pipeline elevation changes do not
The only limitation is that high-pressure fractionation influence pressure loss very much because the transport of
must occur at a pressure safely below the critical pressure natural gas is in a single-phase flow and because of the low
at every stage of the column to ensure that liquid and vapor density of the gas.
phases will be present. The designer must also be con- The design and analysis of natural gas pipelines involve
cerned about the effect of pressure on the relative volatility the use of the gas flow equation:
of the key components in the fractionating column.
  ( P1 – P2 ) 
0.5
2 2
As the operating pressure of the fractionating column T
increases, the relative volatility decreases, making it more
Qs = k  s   (11.7)
 Ps   dZTfL 
difficult to get a clean separation between the two key
components. The operating pressure of a fractionating where:
column is normally set by a desired component separa- k = gas flow equation constant (=7.574 × 10−4 using SI units),
tion and the temperature of the reflux condenser cooling Ts = temperature at standard conditions,
medium (i.e. air, water, and refrigerant). This pressure is Ps = pressure at standard conditions,
the minimum pressure at which the column can operate P1 = upstream pressure,
at the chosen condenser temperature. The pressure will P2 = downstream pressure,
correspond to the bubble point or the dew point of the d = relative density of the gas,
column overhead product. The overhead product will Z = gas compressibility factor,
be at its bubble point for a liquid product (total con- T = flowing temperature,
denser) or at its dew point (partial condenser) for a vapor f = pipe friction factor,
product. L = length of the pipe.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Copyright ASTM International

AST-MNL58-11-0801-011.indd 260 3/12/13 2:17 PM

Chapter 11 n Natural Gas Conditioning and Processing 261

From equation 11.7 it can be observed that the capac- 11.5 Natural Gas Liquefaction
ity of the pipe (Qs) is a function of the upstream pipe pres- Natural gas liquefaction is the process that converts natural
sure, pressure drop, pipeline diameter, and pipeline length. gas into LNG by cooling it to –163°C. Figure 11.11 shows
It accounts for variations in compressibility factor, kinetic the different stages in a liquefaction plant. The major com-
energy, pressure, and temperature for any typical line sec- ponents of an LNG plant are
tion. The equation also involves the friction factor, which • Pretreatment
fundamentally relates the energy lost due to friction. The • Gas reception facilities
friction factor is a function of the flow regime and pipe • Acid gas removal
roughness. • Dehydration
Typically, transmission pressure can be in the range • Mercury removal
of 4–7 MPa and pipe diameters from 60 to 120 cm. For • Gas precooling and heavy (NGL) hydrocarbon
long-distance pipelines, compressors are essential to removal
boost up the pressure lost by friction. Compression within • Liquefaction
limits set by the maximum operating pressure of the pipe- • Storage and export
line is also an alternative to increase additional pipeline • N2 removal
capacity. • LNG and NGL storage
Once the pipeline diameter is fixed, the quantity of • BOG handling
gas that can be delivered is then fixed by the pressures. At • LNG (and NGL) ship loading facilities
times, capacity can be increased by adding compressors
along the pipeline, installing an extra pipe in the form of 11.5.1 Types of LNG Plants
loops, or increasing the average pipeline pressure. There are different ways to categorize LNG plants; the most
Overland pipelines are extensively used throughout usual are based on the size and mode of operation. Thus,
Europe and the United States. Subsea pipelines over 3000 according to the size, an LNG plant can be
km have been regarded as uneconomic because pipeline • Mini: <0.1 MTA
installation and maintenance are very expensive and any • Small: 0.1–1 million tons per annum (MTA)
recompression along the route is difficult. • Medium: 1–3 MTA
• Large: 3–6 MTA
11.4.3.3 Comparative Cost of Moving • Mega: >6 MTA
Gas by Pipeline and as LNG According to the mode of operation, there are two types of
As mentioned earlier, natural gas is more complex and LNG plants:
generally more expensive to store and transport because of 1. Baseload plants: Baseload plants are in operation
its physical nature, which requires high pressures, very low throughout the whole year. This type of plant has been
temperatures, or both. Figure 11.10 shows the comparative used for more than 40 years as an option to monetize
cost of moving gas by pipeline (offshore and onshore) and gas reserves (i.e., to allow the transport of gas from
LNG [20]. the field to the market). It is worth mentioning that
one of the main targets of liquefaction technologies for
11.4.3.4 Natural Gas Liquefaction and baseload plants is to achieve a high efficiency. The first
Regasification baseload liquefaction plants had a production capacity
The LNG chain comprises pretreatment, liquefaction of the of approximately 1 MTA, but this capacity has increased
gas, its transportation in bulk carriers, regasification at the over the years to take advantage of the economies of
point of delivery, and the transportation to the final users scale; nowadays, capacity can be up to 10 MTA per liq-
also through high-pressure pipelines. uefaction train. Baseload plants can also be found at a
mini or small scale. The plants that produce vehicle fuel

3.5

Gas Pipeline Gas Pipeline

3 Onshore
Offshore

2.5
LNG
2
US$/GJ

1.5

0.5

0
0 1000 2000 3000 4000 5000 6000 7000 8000
Distance to Market (km)
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 11.10—Indicative cost of moving gas by pipeline and LNG.

AST-MNL58-11-0801-011.indd 261 3/12/13 2:17 PM

262 Petroleum Refining and Natural Gas Processing

Pre-treatment
Feed Storage and LNG to
(Removal of NGL Removal Liquefaction
Gas Export Facilities tankers
impurities)

Acid Gas
Fractionation
Treatment

Natural
Sulphur Ethane LPG
Gasoline

By-products

Figure 11.11—Block flow diagram of a typical liquefaction plant.

LNG, with capacities ranging from 10–400 t/day are an 11.5.2.2 Compressors and Drivers
example. They have arisen mainly in the United States Refrigerant compressors and their drivers have been a
(e.g., California), where an increasing interest in LNG focus of improvement in LNG plant design through the
exists as an alternative fuel for buses, trucks, and taxis. years. Centrifugal compressors are normally utilized in
The LNG supplied by small baseload plants can also be LNG plants, although axial-flow machines can also be used.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
used to produce compressed natural gas (CNG) for nat- Refrigerant compressors are the most energy-
ural gas vehicles. Other uses of mini or small baseload demanding part of an LNG plant. In the earliest plants,
LNG plants include the natural gas supply to remote the steam turbines were the preferred option to drive these
areas by truck, rail, or barge LNG transportation. compressors; however, the need of a complete steam and
2. Peak-shaving plants: Peak-shaving plants are designed water treatment system constitutes an important disad-
and operated to cover peaks of gas demand. During vantage for this solution. Thus, steam turbines gave way to
the summer months, the energy supply companies heavy-duty gas turbines, which have been the main com-
may buy larger quantities of gas than required for pressor drivers selected for the last few years. As the capac-
average consumption. This excess is liquefied and ity of the LNG plant increased, the size and power output of
stored as LNG. In the winter months, that LNG allows the gas turbines used as drivers also increased.
for meeting the requirements of peak consumption. Aeroderivative gas turbines are, for some years now,
Peak-shaving LNG plants typically have capacities of an alternative to heavy-duty gas turbines because of their
10–200 t/day and operate 150–200 days a year. There higher thermal efficiency and lower weight. However, they
are more than 240 peak-shaving plants worldwide, present some limitations in size and their cost per unit of
particularly in the United States, the Netherlands, power is higher. Darwin LNG is the first baseload LNG
Germany, the United Kingdom, and in other highly plant to use this type of turbine as a mechanical driver.
developed gas supply regions [21]. In recent years, the option of using electric motors as
compressor drivers has also arisen mainly because of the
11.5.2 Major Equipment in an LNG Plant benefits in availability they can provide. The first application
11.5.2.1 Heat Exchanger of this solution is the Hammerfest LNG project (Snøhvit,
The main cryogenic heat exchanger (MCHE) is the heart Norway). The installation of a combined cycle power plant
of the liquefaction process. There are two main types (CCGT) to supply the electricity that these motors require
of MCHE: brazed aluminum plate-fin heat exchangers can add efficiency and environmental advantages to this
(BAHX) and spiral wound heat exchangers (SWHE). alternative, although investment cost increases.
BAHX are manufactured by vacuum brazing tech-
nology. They can treat many process streams in only one 11.5.3 Liquefaction Technologies
unit, which avoids expensive interconnecting piping. The 11.5.3.1 C3-MR Process
aluminum alloys used for the fabrication of these heat The C3-MR liquefaction process accounts for nearly 90 %
exchangers provide the best possible heat transfer, allow of the world’s baseload LNG capacity. The typical C3-MR
the application for low-temperature service, and drastically process uses propane in the precooling refrigeration cycle
reduce the equipment weight. There are several manufac- and a mixed refrigerant (MR) composed of N2, methane,
turers of this type of heat exchanger. ethane, and propane for the liquefaction cycle [22]. As can
SWHE consist of at least one spiral-wound tube bundle be observed in Figure 11.12, a multistage propane cycle pre-
housed within an aluminum or stainless steel pressure cools the feed gas and partially condenses the MR from the
shell. For LNG service, these heat exchangers may consist MR compressor by using kettle-type heat exchangers. The
of up to three tube bundles, each one made up of several partially condensed MR feeds the MCHE (a spiral-wound
tube circuits. The spiral-wound heat exchanger is known type exchanger), where it is autocooled and expanded so as
for its robustness, in particular during startup and shut- to achieve matching cooling curves with reasonably small
down or plant trip conditions. Air Products and Linde are temperature difference. The natural gas is liquefied in the
the only companies capable of manufacturing SWHE. MCHE.
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Chapter 11 n Natural Gas Conditioning and Processing 263

Figure 11.12—C3-MR process. Source: Figure courtesy of Air Products and Chemicals, Inc.

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There are many possible combinations of gas turbine LNG, Kenai, and Egypt LNG). The Optimized Cascade pro-
drivers for the refrigerant compressors. Recent LNG proj- cess (Figure 11.13) was developed from a classical refriger-
ects have used GE Frame 5, 6, and 7 machines as com- ant cascade system in which the lowest boiling temperature
pressor drivers. The C3-MR process implemented with the stage of each refrigerant is used in turn to condense the next
Split MR™6 machinery configuration has the flexibility refrigerant. The process uses pure refrigerants in the con-
of efficiently using all available power from the drivers to secutive cooling steps, namely propane and ethylene, both
handle changing ambient conditions. In the Split MR con- in closed cycles, and finally methane in a multistage open
figuration, the low- and medium-pressure MR compressor cycle. Core-in-kettle-type heat exchangers and plate-fin heat
stages are driven by one gas turbine and the high-pressure exchangers are used for cooling the natural gas and for
MR and the propane compressor are driven by a second gas cold recovery. Several aluminum exchangers are distributed
turbine, allowing for the power split between propane and within the insulated steel cold boxes.
MR refrigeration to be optimized. To limit the compression ratio of the methane compres-
sor, the LNG rundown is above atmospheric pressure and runs
11.5.3.2 ConocoPhillips Optimized flashing into the LNG tanks. The BOG from tanks forms part
Cascade®7 Process of the methane cycle. To limit the buildup of N2 in the methane
Far behind C3-MR, the ConocoPhillips Optimized Cascade cycle, fuel gas is taken from the methane compressor.
process has been used in several LNG plants (e.g., Atlantic The main characteristics for the Optimized Cascade
process are
• Different combinations of compressors and drivers are
6
Split MR™ belongs to Air Products and Chemicals, Inc., Allentown,
PA. possible so as to better fit desired LNG train capacity.
7
ConocoPhillips Optimized Cascade® belongs to ConocoPhillips, • High LPG recoveries (>95–96 %) are achievable with
Houston, TX. the conventional process design.
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264 Petroleum Refining and Natural Gas Processing

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 11.13—ConocoPhillips Optimized Cascade® process. Optimized Cascade is a registered trademark of ConocoPhillips, Co.

• Current maximum train size for the Optimized Cas- 11.5.3.4 Liquefin™9 Process
cade process is approximately 5 MTA LNG (train 4 The Liquefin process is a new liquefaction process com-
of Atlantic LNG). However, this process could theo- mercialized by Axens and developed by the French Institute
retically achieve megatrains of up to approximately of Petroleum [24]. This process has not been industrially
8 MTA. implemented yet.
• Makeup for the propane cycle is obtained from the feed The Liquefin process is a dual MR cycle process that
gas, whereas ethylene has to be imported. is based on the use of plate-fin heat exchangers (PFHEs)
in the exchanger line. When compared with the C3-MR
11.5.3.3 AP-X®8 Process process, the precooling mixed refrigerant (MR1) operates at
In recent years, interest has grown in ever-larger train a much lower temperature, which is adjusted to maximize
capacities so that economies of scale can significantly the use of available power. At this temperature, the cryo-
reduce the unit cost for LNG. To meet this requirement, Air genic mixed refrigerant (MR2) is completely condensed,
Products has developed and patented the AP-X liquefaction and no phase separation is necessary. Both MRs are used
process. as if they were pure components: the MR is condensed and
The Air Products AP-X process (Figure 11.14) is an vaporized at different pressure levels in each section, with-
improvement to the C3-MR process in which the LNG is sub- out any phase separation or fractionation.
cooled using a third cycle with a N2 expander loop. The use of All of the heat exchange between the natural gas and
this third stage makes feasible an important capacity increase the MRs (and between the two MRs) is done in a single
by reducing the flow of propane and MR necessary in the exchanger line made of PFHEs inside of a limited num-
cycles for the same production. With this process, mega ber of cold boxes. The exchanger line is modular: each
capacities of trains (up to 8–10 MTA per liquefaction line) can cold box contains several parallel lines of two cores in
be achieved without duplicated or parallel equipment. series. The number of cores and cold boxes depends on
One of the advantages of this technology is its flexibil- the desired capacity. Figure 11.15 presents the typical pro-
ity because it is possible to operate at a reduced capacity of cess scheme for the Liquefin process. The main process
65 % without the N2 expander loop by adjusting the compo- features are
sition of the MR [23]. • A single exchanger line, made of PFHEs inside of a
The first plant to use this technology is in Qatar. This is few cold boxes, is used to cool and liquefy the natural
also the first plant to use Frame 9 turbines as drivers.

Liquefin™ belongs to Axens-IFP Group Technologies, Rueil-

8
AP-X® belongs to Air Products and Chemicals, Inc., Allentown, PA. Malmaison, France.
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Chapter 11 n Natural Gas Conditioning and Processing 265

Figure 11.14—AP-X® process. Source: Figure courtesy of Air Products and Chemicals, Inc.

Figure 11.15—Liquefin™ process. Source: Figure courtesy of Axens, all rights reserved.
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AST-MNL58-11-0801-011.indd 265 3/12/13 2:17 PM

266 Petroleum Refining and Natural Gas Processing

TM
Figure 11.16—The version of the Shell Double Mixed Refrigerant (DMR ) process as applied in the Sakhalin LNG plant.

gas, achieving very low-temperature approaches and eration and so increases overall LNG capacity. With this
low-pressure drops. Both aspects, together with other process, an LNG plant can achieve 5–8 MTA of capacity.
process features, lead to achieving a high overall pro- The Shell DMR liquefaction process uses SWHEs for the
cess efficiency, which minimizes the fuel gas consump- precooling and main cooling cycles.
tion and the resulting CO2 emissions per ton of LNG Other benefits of the DMR cycle are the minimization
produced. of hydrocarbon inventories compared with the single MR
• Because the cold boxes are modular, there is no size cycle or the C3-MR cycle, which reduces flaring rates in the
limitation for the exchanger line. Hence, by implement- event of compressor trip and refrigerant blowoff.
ing parallel compressor lines, this liquefaction technol- The first commercial application of this technology
ogy can be used for megatrains. is in Sakhalin LNG, with a capacity of 4.8 MTA per train
• The process can be designed to use any type of mechan- (two trains).
ical driver (GE Frame 5, 6, 7, 9, aeroderivatives) or Another process offered by Shell, especially indi-
electric motors as compressor drivers so as to best fit cated for large plants (megacapacity trains can be
the desired LNG production. achieved), is parallel mixed refrigerant (PMR), which
consists of one precooling cycle (with propane or a MR)
11.5.3.5 DMR and PMR Shell Processes and two parallel MR cycles. The parallel lineup of the
The configuration of the dual mixed refrigerant (DMR) liquefaction cycles improves the reliability of the train
process (Figure 11.16) is very similar to that of C3-MR; that because the LNG production can be designed to continue
is, two independent refrigerant cycles—one for precool- at 60 % of the train capacity when one of the liquefaction
ing and one for liquefaction. However, DMR uses a MR (a cycles trips [25].
mixture of ethane and propane) for precooling instead of
pure propane. On the other hand, the MR for liquefaction 11.5.3.6 MFCÒ10 Linde Process
is a mixture of N2, methane, ethane, and propane. The use Linde and Statoil have developed a baseload LNG process
of two MRs facilitates the process optimization to a wide called Mixed Fluid Cascade (MFC) process. This process
range of ambient temperatures. The use of a MR in the first can be used for an LNG train capacity from 3 MTA to mega-
cycle removes the propane compressor bottleneck existing capacity trains. In this process, the pressurized natural gas,
in the conventional C3-MR process, where the compressor once pretreated, is precooled, liquefied, and subcooled by
size is limited by the Mach number at the blade tip; using means of three separate MR cycles (Figure 11.17).
a lower-molecular-weight MR, the Mach number is reduced The refrigerant used in the precooling cycle is com-
and the tip speed limit is extended. posed of ethane and propane, whereas that used for the
In addition, any excess power available from the gas liquefaction cycle is a mixture of methane, ethane, and
turbine that drives the precooling compressor can be trans- propane, and the subcooling refrigerant is a mixture of N2,
ferred to the second cycle. In this way, the DMR method
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

allows a full utilization of the available power for refrig- 10

MFC® belongs to Linde, Munich, Germany.
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Chapter 11 n Natural Gas Conditioning and Processing 267

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Figure 11.17—MFC® process. Source: Figure courtesy of Linde Engineering.

methane, and ethane. The natural gas precooling is per- accomplished in one stage. This implies that the SWHEs
formed in PFHEs, reaching a temperature of approximately do not constitute the limiting factor for the size of the liq-
–50°C in the natural gas side. On the other hand, the liquefaction train, and the capacity of a single LNG train can
uefaction and the subcooling cycles utilize SWHEs. The be increased.
temperature of the natural gas after the liquefaction stage Other benefits of the MFC process are [26,27]
is approximately –90°C and approximately –155°C after • No separator is needed, so large pieces of equipment
the subcooling stage. Finally, the LNG is depressurized to are avoided.
atmospheric pressure using a turbine, reaching a tempera- • Less circulating hydrocarbon is needed, which has ben-
ture of –163°C. eficial effects with respect to the volume and safety of
The three-cycle compositions enable optimized match flammable hydrocarbons.
to the three sections of the natural gas cooling curve com- • The MR circulation rates can be directly adapted for
pared with one- or two-cycle mixtures; this offers higher the three mixtures and do not depend on two-phase
efficiency or low-energy requirement [26]. The three refrig- equilibrium in a separator.
erant compression systems can have separate drivers or be • Lower emissions.
integrated in two strings of compression. This first commercial application of this technology is
The main advantage that this technology offers is in Snøhvit, with the Hammerfest LNG project on Melkøya
that liquefaction and subcooling capacity is split into two Island (Norway), with a capacity of 4.3 MTA.
stages; thus, the suction volumes of the liquefaction and
subcooling compressors are smaller and both SWHEs are 11.5.3.7 Other Technologies
of similar size, with smaller diameter than the SWHEs of The other technologies considered for natural gas lique-
the processes in which the liquefaction and subcooling are faction can be classified into two different categories: MR
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268 Petroleum Refining and Natural Gas Processing

processes or turboexpander-based processes. Regarding cy can be improved by adding a closed loop of propane
MR processes, the main ones are the following: for precooling (OCX-R process). The NDX-1 process,
• PRICO®11 (Poly Refrigerant Integrated Cycle Opera- mentioned above, is included under the LNG Smart®
tion) process, licensed by Black & Veatch Pritchard liquefaction processes.
Corporation, is a single MR process. It was used in
Skikda (Algeria) in the early 1980s for baseload LNG 11.5.3.8 FLNG
production. Offshore liquefaction appears to be a technically feasible
• APCI single MR process, licensed by Air Products, uses possibility, and it is foreseen as an opportunity to monetize
a single multicomponent refrigerant in several refrig- new gas resources (e.g., stranded gas). An offshore LNG
eration stages. There is only one LNG plant using this plant could be placed on a fixed or gravity-based structure,
process (Marsa el Brega, Libya), started up in 1970. but the offshore platform selected for most of the develop-
• TEAL process, licensed by Technip, is a single MR pro- ments in the last years is the FPSO. This concept is usually
cess. There exists an improved version called TEALARC referred to as FLNG or LNG FPSO.
developed by Technip/Snamprogetti. The first three The FLNG concept consists of locating a liquefaction
trains in Skikda (Algeria), started in the early 1970s, plant above a barge or ship-shape structure and exploiting
use this process. offshore or near-shore gas fields. This kind of facility is
• Linde’s proprietary Multi Stage Mixed Refrigerant particularly suitable for monetizing stranded gas reserves;
process (LiMuM) is a single MR technology that has that is, reserves that are not economically viable using con-
been used for small-scale LNG plants (<0.5 MTA). It is ventional technology (pipelines or onshore LNG plants). A
considered as a good alternative to turboexpander pro- FLNG plant can also be utilized for monetizing associated
cesses for floating medium-scale LNG plants (capacity gas in offshore fields or for early production in gas fields.
achievable: 2.5 MTA). One of the advantages is the mobility of the facility; theo-
The turboexpander-based processes have been typically retically, the same plant could be used for the exploitation
selected for small-scale liquefaction plants, particularly of several fields through its lifetime, although there exist
the N2 refrigeration cycle (explained below). Some floating limitations regarding feed gas composition and site Met-
liquefied natural gas (FLNG) designs are also proposing ocean conditions. On the other hand, the floating feature of
these processes for their application offshore because of the facility imposes significant constraints and drawbacks
their simplicity of operation, shutdown and ease of restart, because of the continuous motion of the system, which
low equipment count, low deck space requirement, low affects equipment design, operability, and availability. For
sensitivity to vessel motion, low weight, and avoidance of this reason, the process efficiency in this kind of plant is
hazardous hydrocarbon refrigerants use. not typically deemed as important as the safety, simplicity,
• N2 refrigeration cycle is the most common compactness, ease of operation, quick startup, and avail-
turboexpander-based process, in which compressed ability. Together with these parameters, the main factor that
N2 is expanded to provide the required cold duty to must be faced by a FLNG plant is the berthing and loading
liquefy the natural gas. The refrigerant is kept in gas- of LNG carriers, which constitutes a major technological
eous phase throughout the cycle and the liquefaction challenge.
is achieved in a less efficient but simpler manner than
MR technologies (a gas with uniform flow rate through 11.6 LNG Regasification
the cycle cannot closely match the process gas cooling Regasification terminals, also referred to as “import ter-
requirements). Efficiency can be increased by using minals,” take charge of receiving LNG carriers, storing
several refrigeration stages. Some of the companies LNG, and vaporizing it according to gas demand. They are
that offer processes based on the N2 refrigeration cycle intended to provide the necessary infrastructure to link
are APCI, Hamworthy (Mark I, Mark II, Mark III pro- the natural gas producers to the final markets. The main
cesses), Mustang Engineering (NDX-1 process), and purposes of these receiving facilities are to meet growing
BHP (Compact LNG process, cLNG™12). natural gas demand and to increase flexibility by reducing
• CB&I Lummus has developed a process called Dual the dependency of a single supplier (as for pipelines).
Independent Expander Refrigeration Cycle (Niche Nowadays, there are more than 50 LNG import termi-
LNGSM13) that includes one methane cycle and one N2 nals in operation around the world. Most of them (64 %) are
cycle and improves the efficiency achieved in compari- located in Asia, particularly in Japan and Korea, whereas
son to other expansion-based processes. This process is nearly 75 % of the proposed or under-construction terminals
applicable for onshore, near shore, or offshore applica- are planned for the European and U.S. markets [29].
tions [28].
• LNG Smart®14 liquefaction processes, developed 11.6.1 General Description of the
by Mustang, are specifically designed for floating Regasification Process
medium-scale LNG plants. The OCX-2 (Open Cycle Figure 11.18 shows the process flow diagram of a typical
Expander) process consists of an open refrigeration LNG receiving terminal. The LNG is offloaded from the
loop that uses the source gas as refrigerant. Its efficien- LNG carriers and stored in insulated tanks located in the
import terminal. Because gas is required to be injected
into the grid, the primary pumps pump out a liquid stream
11
PRICO® belongs to Black & Veatch, Kansas City, MO.
12
cLNG™ belongs to BHP Billiton, Melbourne, Australia. from the tanks. It can be directed either to the recondenser,
13
Niche LNGSM belongs to CB&I Lummus, The Hague, The Neth- when the terminal has this piece of equipment for vapor
erlands. handling, or directly to the high-pressure pumps (also
known as secondary pumps), when there is no recondenser.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
14
LNG Smart® belongs to Mustang, Houston, TX.
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Chapter 11 n Natural Gas Conditioning and Processing 269

Figure 11.18—Process flow diagram of an LNG import terminal.

The liquid stream from the secondary pumps is vaporized the offloading operation is completed. LNG carriers are
in the vaporizers. The phase change requires the addition berthed in the jetty while LNG is pumped out using the
of heat, which can be done using different technologies; the pumps located in the vessel itself. The LNG is conducted
amount of energy depends on the composition of the LNG through the offloading arms and the pipeline routed to
and the final temperature required. Before being delivered shore over the trestle. Part of the vapor displaced from the
to the grid, natural gas must be metered for billing pur- tanks during the offloading operation is sent to the carrier
poses and odorized for safety reasons. through a vapor return arm.
Another important part of the LNG import terminal
process is the vapor handling system. BOG is continu- 11.6.2.2 Storage System
ously produced inside of the storage tanks because of The storage system consists of one or more specially
external heat input. To maintain the internal pressure at designed tanks that provide a buffer between the discharge
a constant level, the generated BOG must be processed. from the ships and the vaporization. Further description of
During the offloading of an LNG carrier, larger quanti- the type of storage tanks is presented under LNG Storage.

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ties of vapor are produced mainly because of energy In regasification plants, special attention is to be paid
input from the unloading pumps of the LNG ship and to LNG stratification and rollover. Terminals receive LNG
also from heat in-leak in the transfer line. There is also a from different locations, and therefore with different com-
significant amount of vapor due to the displacement pro- positions and densities, which can cause stratification. If
duced in the tanks. Part of this vapor is returned to the one of the upper layers has a density higher than the lower
tanker, but the rest must be also processed. There are two ones, a rapid mixing between layers, known as “rollover,”
approaches for BOG processing: compression up to the can happen. This would lead to a huge amount of BOG
discharge pressure and injection into the pipeline grid, generation, which the plant may not be able to process. To
used in terminals without recondenser, or compression prevent this phenomenon, terminals have lines to circulate
up to the primary pump discharge pressure and sending LNG between tanks and use different filling procedures
to the recondenser where it is reliquefied by direct con- (bottom filling and upper filling) to cope with density dif-
tact with subcooled LNG. The main process systems in a ferences between stored LNG and unloaded LNG.
regasification facility will be described in more detail in
the following sections. 11.6.2.3 LNG Pumpout System
To reach the required pressure for the send-out gas, the
11.6.2 Main Process Systems [30,31] LNG is pumped before its regasification (liquid pumping
11.6.2.1 Offloading System is easier and cheaper than gas compression). There are
The offloading system comprises the equipment and infra- two pressure levels along the LNG flow path. The primary
structure required to dock the LNG tanker and transfer pumps are almost always located inside of the storage
its cargo to the onshore piping, as well as the necessary tanks, so they pump the LNG from a pressure slightly
facilities for disconnecting and undocking the ship once above atmospheric pressure up to an intermediate pressure
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270 Petroleum Refining and Natural Gas Processing

Figure 11.19—ORV at Sumitomo Precision Products, Co., Ltd. (left) and Tokyo Gas, Co., Ltd. (right).

level, typically 7–10 bar (700–1000 kPa). The secondary or 11.7 LNG Vaporization
high-pressure pumps are located outside of the tanks and Several vaporization systems exist for which the main dif-
discharge at a pressure high enough to satisfy the battery ference is the heat source used for the regasification. The
limit pressure at the terminal fence. most important are
• Gas combustion
11.6.2.4 BOG Generation and Handling • Seawater or ambient air as heating medium
BOG is essentially LNG gasified in the storage tanks at • Integration with other facilities with energy surplus
atmospheric pressure because of three factors: The two systems most commonly used are open rack
1. LNG unloaded from the ship is warmer than the tem- vaporizers (ORVs) and submerged combustion vaporizers
perature inside of the storage tanks. (SCVs), although the intermediate fluid vaporizer (IFV) is
2. Heat input due to the LNG pumps. also used in some terminals.
3. Ambient heat transferred through the cryogenic insu- An ORV consists of a group of panels formed by finned
lated pipelines, equipment, and tank walls. tubes with the LNG flowing upward through them (see
The balance of BOG during unloading mode and the Figure 11.19). A film of seawater flows downward outside
BOG generated during holding mode must be processed, of the tubes, absorbing the cold from the LNG and return-
used as fuel in the terminal, or, under certain conditions, ing to the sea a few degrees colder. The heat used is essen-
flared. tially free, although capital and operating costs related
The BOG to be processed is compressed by the BOG to pumping and piping seawater should be taken into
compressors up to the recondenser pressure level or to the account. The use of such vaporizers is not advisable when
discharge pressure, depending on the vapor handling con- the seawater temperature is lower than 5°C.
figuration of the terminal. The SCV consists of a warm water bath with a bundle
New terminals normally have a recondenser because it of tubes immersed in it. The LNG flows through the tubes,
increases the plant efficiency. The energy for compressing a requiring the burning of a certain percentage of the send-
mass of gas is more than 10 times that required for pumpout gas for its vaporization. The hot gases from the combus-
ing the same mass of liquid; the best way to process the tion are bubbled through the water, heating up the bath.
BOG generated is therefore to condense it again. Hence, the hot water acts as an intermediate fluid between
The recondenser consists of a vertical vessel that com- the hot gases and the LNG (see Figure 11.20).
prises an inner packed bed where BOG condenses as it The IFV consists of three shell and tube heat exchang-
comes into contact with subcooled LNG and an outer annu- ers, which use an intermediate heating medium for the
lar space that acts as a liquid buffer volume for the high- energy exchange between seawater and LNG. This interme-
pressure pumps located downstream of the recondenser. diate fluid prevents ice from forming on the heat transfer

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Figure 11.20—SCV. Source: Pictures courtesy of Selas-Linde GmbH.
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Chapter 11 n Natural Gas Conditioning and Processing 271

surface. This type of vaporizer has high capital costs and reduction in operating cost and in environmental impact,
significant environmental impact because of chlorination among others. The benefits of recovering the available cryo-
and low return temperature. genic energy are not limited to the direct economic return
Some new terminals are beginning to use ambient air generated from the energy recovery itself, but also include
vaporizers (AAVs) to take advantage of the ambient air heat. those related to the reduction in CO2 emissions, the positive
The main advantages are low power consumption and zero impact to the community as a green operator, and the proba-
emissions, although they require a great deal of plot space ble reduction on the grid power consumption, among others.
for their installation. It is advisable to consider the cryogenic energy recov-
Other vaporization technologies used for small-scale ery from the beginning in an LNG import terminal project.
regasification terminals are heating water tower, intermediate During the initial project definition stages, important fac-
thermosyphon vaporizer, quench water vaporization system, tors can be taken into account to take full advantage of
and reverse cooling tower technologies. the available energy with a minimal interference into the
The selection of the type of vaporizer to be used in regasification process. Some of them are
a specific terminal depends on several factors, such as • To use the cryogenic energy at the lowest possible tem-
investment cost, operational cost, maintenance, reliability, perature, keeping the process efficiency at a maximum;
availability, footprint, air emissions, and environmental however, the number of applications of such effective
impact. A comparison of vaporizer systems is provided in utilization is very limited.
Table 11.7. In any particular case, the environmental condi- • The natural gas consumption pattern does not neces-
tions of the site to a great extent determine the technology sarily match with the cryogenic energy utilization rate.
selection. ORVs and AAVs are not advisable in cold weather Therefore, the integration system should be designed to
locations; conversely, SCVs and IFVs are more suitable. be capable of coping with variations in gas demands.
Otherwise, the cryogenic energy exchanged will be lim-
11.7.1 Gas Metering and Send Out ited to the minimum send-out capacity of the import
Gas is measured in the receiving terminals for billing pur- terminal.
poses before its injection to the grid. Quantity and qual- • Natural gas must be pressurized before its injection
ity are required. The quantity can be measured by orifice in the pipeline grid. It is more economical to pressur-
plates and ultrasonic and turbine flow meters, among ize LNG before gasifying it; however, extracting LNG
others. The quality of the natural gas is normally analyzed cryogenic energy at high pressure is less profitable
by chromatography. because the amount of available energy is lower than
Before the send out, natural gas is odorized by adding the amount at low pressure.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
organosulfur compounds [e.g., tetrahydrothiophene (THT) • The distance between the LNG import terminal and the
and tertiary butyl mercaptan (TBM)] to meet health and cryogenic energy receiving facility should be less than
safety regulations. approximately 3 km because the installation cost of
longer pipelines, heat, inleak, and pressure losses are
11.7.2 Cryogenic Energy Recovery considerable and may make a project unfeasible.
From a thermodynamic point of view, the conventional • Despite having good properties as a coolant, LNG
regasification process has in fact a lack of utilization of direct use is limited because of its flammability. To
the available cryogenic energy, which decreases the global avoid any possible explosive mixture, the usual practice
energy efficiency of the liquefied natural gas (LNG) chain. is to use an inert intermediate fluid, although system
Cryogenic energy recovery is technically feasible and has cost and complexity are increased.
already been implemented at many industrial sites. For The available energy in the vaporization process can
instance, Japan started using cryogenic energy in air sepa- have a direct or indirect use. Table 11.8 shows the main
ration units in the 1970s. applications in which the cryogenic energy can be used.
Cryogenic energy can be used for several applications, The applications of a greater importance are those related
all of which are intended to increase the efficiency of the to cryogenic air separation and power generation, by its
processes involved and capitalize the benefits related to it: integration with an existent power generation facility, or

Table 11.7—Comparison of Vaporizer Systems [32]

Capital Installation
Technology Cost Cost Power Fuel Maintenance Emissions Space Simplicity
Open rack ORV – – 0 ++ – 0 0 –
Submerged SCV ++ ++ – – 0 – 0 0
combustion
Air–natural AAV + + ++ ++ ++ ++ – ++
draft
Air–forced FAV + – + ++ + + 0 +
draft
Intermediate IFV – 0 – ++ – – 0 –
fluid
+, positive feature of the technology; –, negative feature of the technology; 0, neutral feature of the technology.
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272 Petroleum Refining and Natural Gas Processing

Table 11.8—Potential Uses for Cryogenic Energy

CRYOGENIC ENERGY RECOVERY Integration with power generation facilities Cooling of condensate
Cooling of inlet air to the gas
turbine (GT)
Cooling of exhaust from the GT
Integration with cryogenic facilities Cryogenic air separation
CO2 liquefaction
Dry ice production
Food conservation
Integration with other facilities Seawater desalinization
HHV adjustment
Direct power generation Rankine cycle
Inverted Brayton cycle

i n-house power generation by means of a Rankine cycle. For example, the air separation unit at Tokyo Oxygen
When analyzing an integration scheme, it is important to and Nitrogen Co., Ltd. is placed next to the Sodegaura LNG
consider the impact on the receiving facility. If no third import terminal, operating in an integrated manner since
party is involved, the recovery unit can be started up and 1978. Another example is a refrigerated warehouse next
shut down whenever is convenient according to the LNG to the Negishi import terminal (Tokyo), the Japan Super
import terminal send-out and other operational param- Freeze Co., Ltd., operating since 1974 [33].
eters.
11.7.2.3 Integration with Other Facilities
11.7.2.1 Integration with Power Generation LNG cryogenic energy can also be used in many other
Facilities process facilities that require refrigeration, as for seawa-
Integrating the import terminal with a combined-cycle or ter desalinization using crystallization technology, or for
an open-cycle gas turbine power generation plant offers natural gas HHV adjustment by means of NGL extraction.
a considerable positive impact for both facilities. Fur- Trunkline LNG Company is planning to install an HHV
thermore, the capital cost is reduced, and there is a lower adjustment facility at their Lake Charles terminal (United
environmental impact because of the reduction of emis- States) [34].
sions, thermal pollution, and chlorination of water. When
integrated, the power plant becomes the sink of the LNG 11.7.2.4 Power Generation
cryogenic energy available in the import terminal. There Finally, it is worth highlighting the direct power generation
are several configurations that allow for the proposed inte- by means of a Rankine cycle or an inverted Brayton cycle,
gration depending on the end use of the cryogenic energy: commonly called a mirror gas turbine. The LNG cryogenic
• Cooling of condensate water (for combined-cycle energy condenses the working fluid used in the Rankine
power plant) cycle, or cools down the exhaust gas from a turbine in the
• Inlet air cooling inverted Brayton cycle, recovering its energy under the
• Exhaust gas cooling atmospheric pressure level.
An example of this way of integration is Bahía de Among others, the LNG import terminal of Negishi
Bizcaia Gas (BBG), a Spanish import terminal, which is generates 4 MW using the Rankine cycle. Despite the pre-
integrated with a combined-cycle power plant Bahía de dicted thermodynamic efficiency improvement using the
Bizcaia Electricidad, BBE (800 MW). There is an inter-
mediate pool where the power plant pours hot water from
the steam condenser; the LNG import terminal takes water
from that pool to use it in the ORVs (see Figure 11.21).

11.7.2.2 Integration with Cryogenic

Facilities
Cryogenic facilities require high power consumption to pro-
duce the refrigeration required for the process. Cryogenic
energy recovered from LNG could significantly decrease
the aforementioned power consumption.
Integration schemes that use lower temperatures are
preferred because they take full advantage of the available
energy from the LNG. Therefore, the most relevant appli-
cations of LNG cryogenic energy recovery for integration
with cryogenic facilities are those related to cryogenic air Figure 11.21—LNG import terminal integrated with a power
separation, CO2 liquefaction, dry ice production, and food generation plant (BBG-BBE). Source: Picture courtesy of Bahía
conservation. --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
de Bizkaia Gas, S.L.
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Chapter 11 n Natural Gas Conditioning and Processing 273

mirror gas turbine, no power system using this principle plant is free to operate independently of any variability
has been built to date. in the LNG chain from production, shipping, or market
demand. The main aspects regarding storage in an LNG
11.7.3 Offshore LNG Import Terminals plant are total storage capacity, tank size, and containment
Traditionally, conventional terminals have been placed technology of the tank.
onshore; however, several factors are driving the regasifica-
tion facilities offshore: fast implementation, lower social 11.8.1.1 Storage Capacity
impact [the “not in my back yard” (NIMBY) effect], and The LNG industry is in the process of optimizing the entire
environmental constraints (difficulty in obtaining permits LNG chain through economies of scale. Liquefaction
for onshore plants). throughput and ship size have increased over recent years.
There are different approaches for designing and oper- To adapt to these increases, the storage capacity of LNG at
ating offshore facilities depending on the final markets and liquefaction and regasification terminals has also grown.
infrastructure requirements. The main variables to be con- A simplified calculation of the desirable storage capacity
sidered during the design stage are the water depth, the dis- for a particular plant would be the higher number between
tance from shore, and the storage capacity required. Water the volume delivered by the largest LNG tanker contracted
depth determines the type of structure to be considered; the and the volume of the LNG allocation logistic model. Nev-
minimum depth is constrained by the safe maneuvering of ertheless, at the end must be plant owners, who define the
the LNG carriers—typically 14 m of draft. Other parameters storage philosophy on the basis of the business structure,
that define safe and economic operation are wave action contracts in place, and client demands.
and the relief of the seafloor, among others. Another way to look at the storage capacity is in terms
There is a simple classification of offshore terminals of days of LNG production or gas send out. In liquefaction
depending on the type of structure: plants, the storage capacity usually ranges from 5 to 8 days
• Fixed structures are appropriate for shallow-water off- of liquefaction capacity. The storage capacity in regasifica-
shore locations and where the seafloor is relatively lev- tion terminals depends more on demand shapes and it is
eled and the sediments are able to support the founda- typically approximately 10–20 days of the terminal capac-
tion and weight of the structure. There are mainly three ity. Some Japanese terminals supplying power plants tend
types: gravity-based structures, offshore platforms, and to have an even larger storage capacity [31]. Tables 11.9

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
artificial offshore islands. and 11.10 show the storage capacity for some liquefaction
• Floating structures are considered when water depth plants and regasification terminals.
increases beyond permissible limits for fixed structures
(although they can be applied in some shallow water 11.8.1.2 LNG Tanks: Types and Sizes
applications). There are two types depending on wheth- LNG is stored in tanks at temperatures of approximately
er storage capacity is included or not: floating, storage, –160°C and pressures slightly above atmosphere at its
and regasification units (FSRUs) and floating regasifi- bubble point. Storage tanks can be classified into three cat-
cation units (FRUs). egories: underground, in ground, and above ground (Fig-
The operation of the LNG import facility depends on its ure 11.22). Underground and in-ground storage tanks have
storage capacity. Terminals with sufficient storage capacity a higher level of safety but also have a higher investment
can supply natural gas on a constant basis, whereas those cost; they are mainly applied in earthquake-prone regions
without associated storage must deliver natural gas in an such as Korea and Japan. There are three main above-
intermittent way, at the same rate that the LNG carriers off- ground tank containment types: single containment, double
load in the regasification facility. containment, and full containment (Figure 11.23). Techni-
cal features and main advantages of above-ground tank
11.8 LNG Storage containment technologies are described in Table 11.11.
11.8.1 Overview The trend over the years, as Figure 11.24 shows, has
The objective of the LNG tank at the receiving terminal and been to evolve from single containment, through double
liquefaction plant is to act as a buffer. Thus, the processing containment, to full containment because of the increase

Table 11.9—Example of Liquefaction Plant Storage Capacity [35]

Storage Capacity
Plant Capacity Number of Tank Capacity
Name Country (MTA) 1000 m3 LNG Days Tanks (1000 m3 LNG)

Malaysia LNG (F1–F3) Malaysia 23.3 445 3 6 65–120

Nigeria LNG (T1–T5) Nigeria 18.2 337 3 4 36–84

Bethioua (GL1Z–GL2Z) Algeria 16.5 600 5 6 100

Atlantic LNG (T1–T4) Trinidad 15.3 560 5 4 120–160

Tangguh Indonesia 7.6 340 6 2 170

Peru LNG Peru 4.5 260 8 2 130

Snøhvit Norway 4.1 250 9 2 125

AST-MNL58-11-0801-011.indd 273 3/12/13 2:17 PM

274 Petroleum Refining and Natural Gas Processing

Table 11.10—Example of Regasification Terminal Storage Capacity [35]

Storage Capacity
Individual Tank
Plant Capacity Installed Capacity Days of Number of Capacity
Name Country (MTA) (103 m3 LNG) LNG Storage Tanks (103 m3 LNG)

Sodegaura Japan 39.9 2660 13 35 60–140

Incheon South Korea 35.2 2080 12 16 100–200

Barcelona Spain 18.2 680 7 8 40–150

Senboku II Japan 17.5 1585 18 22 75-180

Huelva Spain 12.5 610 10 4 60–150

Canaport Canada 10.4 320 6 2 160

Dapeng LNG China 4.9 480 19 3 160

in safety and reduced plot space. Full containment type and footprint. Moreover, the construction schedule, which is
is extensively used in LNG import terminals. However, in commonly in the critical path of LNG project execution, is
liquefaction plants the containment technology is more not increased as the tank becomes larger [37].
project specific.
Because LNG tanks have very high reliability, larger tanks 11.9 Other Natural Gas Technologies
are preferred over multiple smaller tanks. Since the first LNG 11.9.1 Gas-to-Liquids
tank constructed in Canvey Island, United Kingdom, in 1957, 11.9.1.1 Introduction to Gas-to-Liquids
the size has significantly increased over the years, as can be Gas-to-liquids (GTL) is the chemical conversion of natural
seen in Figure 11.24. Currently, the largest above-ground gas into long-chain hydrocarbon liquids, such as naphtha,
tank has a storage volume of 190,000 m3, whereas the larg- diesel fuel, or lubes. The term GTL is also used for the prod-
est in-ground tank has a storage capacity of 200,000 m3 [36]. ucts of the previous process.
Most of the new developments favor above-ground tanks From a business perspective, GTL is mainly envis-
and aim for even larger capacities, up to 300,000 m3. The aged as an option for natural gas monetization—an
main advantages for larger tanks are the economy of scale alternative to the gas transportation options. The high

Figure 11.22—Storage tanks categories [38].

Figure 11.23—Storage tanks containment technologies [38].

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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AST-MNL58-11-0801-011.indd 274 3/12/13 2:18 PM

Chapter 11 n Natural Gas Conditioning and Processing 275

Table 11.11—Above-Ground Tank Containment Features and Main Advantages [31]

Single Containment Double Containment Full Containment

Primary container LNG storage LNG storage LNG storage

Outer shell For retention and protection of For retention and protection of Not applicable
the insulation and for containing the insulation and for containing
the gas phase the gas phase

Secondary container A bund wall or dike surrounding An outer wall capable of Secondary container capable of
the tank capable of containing containing any LNG leakage in a LNG and BOG storage in case of
any LNG leakage but not the BOG reduced area but not the BOG primary container failure

Main advantage Lower capex Tradeoff between single and full Higher safety and lower layout
containment requirement

quality of the products, with virtually no sulfur and very On the other hand, GTL presents several drawbacks
few aromatics, also makes this process very attractive with respect to competitive products and processes:
from the product marketing point of view. From a tech- • Very scarce industrial experience
nology standpoint, Fischer–Tropsch (FT) synthesis is the • Complex technology, so relatively high operational risk
core of the GTL process, to the point that both terms • Low thermal efficiency of GTL processes compared
have become practically synonyms. Strictly speaking, with gas transportation
other processes exist that are also GTL processes, such • Very high capital costs
as methanol synthesis. However, the markets for non-FT
GTL products are much smaller than the markets for FT 11.9.1.2 Fundamentals of the GTL Process
products, so FT synthesis is the only GTL option econom- The GTL process consists of three main stages (
ically viable for large-scale gas monetization projects. 1. Natural gas reforming to produce synthesis gas, a
The main advantages of GTL are mixture of CO and hydrogen (H2). This is achieved by
• The ability to bring large gas reserves to market. a partial oxidation of natural gas using steam, oxygen
• Market diversification: GTL products are addressed to the (O2), or a mixture of them. This step is common to
oil derivative market instead of the natural gas market. all of the GTL alternatives—FT, methanol, dimethyl
• Spot, unconstraint market: GTL products can be easily ether, etc.
transported and stored, which increases commercial 2. FT synthesis, which is the technology core of the GTL
flexibility. process because the chemical structure of the final
• Different product slates can be obtained in a GTL plant. products, and therefore most of their properties, is
• GTL products have higher added value than natural achieved at this step. Synthesis gas is converted to lin-
gas, and the quality is also higher than that of the ear hydrocarbons with variable chain lengths, accord-
equivalent products from crude oil. ing to the reaction CO + 2H2 → –CH–2 + H2O.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 11.24—LNG tank sizes and types with time [37]. Source: Reprinted with permission from the BP Exploration Operating
Company Limited.
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276 Petroleum Refining and Natural Gas Processing

Synthesis
Natural gas gas FT wax Naphtha
Synthesis Gas Fischer-Tropsch Product Diesel fuel
Kerosene
production Synthesis upgrading
Paraffins
Lubes

Oxygen Water

Air Separation
Unit

Figure 11.25—Block flow diagram of GTL processes.

This reaction can be understood as a polymerization- product distributions are obtained. Hence, there exists
hydrogenation reaction of CO. Product molecular some flexibility to decide the final process products,
weight distribution depends on reaction conditions, which may include naphtha, diesel fuel, kerosene, par-
particularly on temperature. In low-temperature FT affin, or lubes, among others.
processes (200–250°C), high-molecular-weight wax (the A more detailed diagram of a typical GTL-FT process is
FT wax) is produced; in high-temperature processes presented in Figure 11.26.
(300–350°C), the products are lighter and remain in
the gas phase at reaction conditions. Nowadays, low- 11.9.1.3 Existing GTL Technologies
temperature processes are preferred because of their A summary of the most developed GTL concepts is pre-
improved economics. Water is always produced in large sented in Table 11.12. A general configuration of existing
quantities as a byproduct (1 mole of water per mole of plants using each technology has been included, as well as
CO reacted). the demonstration level achieved by 2009. FT technology
3. Product upgrading: The FT wax obtained in low- is the distinctive aspect of any GTL concept. In most cases,
temperature processes needs to be further processed the synthesis gas and the upgrading sections, although
to obtain the final GTL products within the required being an integral part of the facility, are not considered part
specifications. This is typically achieved by hydrotreat- of the GTL technology concept and are instead provided
ment/hydrocracking processes, together with product by specialized technologists. The following describes in

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
fractionation. Depending on the process configura- more detail the main options available for the three process
tion and operating conditions in this section, different stages.

Figure 11.26—Typical GTL process diagram (slurry FT technology).

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Chapter 11 n Natural Gas Conditioning and Processing 277

Table 11.12—Main Features of Existing GTL Plants for Different Technologies

Company Synthesis Gas FT Scale

Shell Noncatalytic POX Fixed bed, cobalt Industrial (14,500 bbl/day)

Sasol ATR (Haldor Topsøe) Slurry, cobalt Industrial (34,000 bbl/day)

GTL.F1 (StatoilHydro–PetroSA, Lurgi) Combined reformer (Lurgi) Slurry, cobalt FT demo (1000 bbl/day)

ConocoPhillips Catalytic POX Slurry, cobalt Demo (400 bbl/day)

BP Davy Process Technology Compact SMR Fixed bed, cobalt Demo (300 bbl/day)

ExxonMobil ATR Slurry, cobalt Demo (200 bbl/day)

Syntroleum ATR with air Slurry, cobalt Demo (70 bbl/day)

IFP-ENI – Slurry, cobalt FT demo (20 bbl/day)

11.9.1.3.1 Synthesis Gas Technologies in conventional, large-scale GTL plants. However, some
Three basic process options can be used for synthesis gas SMR options have been proposed for niche GTL appli-
production from natural gas: cations, such as the compact reformer (BP-Davy Pro-
1. Steam methane reforming (SMR): This process takes place cess Technology), which could be an interesting option,
in multitubular reactors. The reaction is highly endo- for instance, for small or medium-scale offshore facili-
thermic, so the tubes are located inside of a fire-heated ties. On the other hand, SMR is the usual process for
furnace (Figure 11.27). Two main reactions are involved H2 production, so from a technical standpoint, it is a
in the SMR process: simple and mature technology. In addition, most GTL
plants include an SMR unit to produce the required H2
CH4 + H2O ↔ CO + 3H2 (11.8) for the third stage of the process (product upgrading).
CO + H2O ↔ CO2 + H2 (11.9) Many technology and engineering companies exist
that can provide SMR units, including Lurgi, Johnson
The first reaction is actually the steam reforming reac-
Matthey, Davy Process Technology, and Haldor Topsøe,
tion, whereas the second is known as the water gas shift
among others.
(WGS) reaction. At process conditions, both reactions
2. Partial oxidation (POX; catalytic or noncatalytic): This
are close to chemical equilibrium. The catalyst, in pel-
process is highly exothermic (Figure 11.28). The main
lets, is typically based on nickel on an alumina support.
chemical reaction that takes place in the system is
To avoid coke formation on the catalyst surface, a high
CH4 + 1/2 O2 → CO + 2H2. Some CO2 and H2O are also
steam-to-carbon ratio must be used. Therefore, the
produced in the POX reactor, so the WGS reaction also
resulting H2/CO ratio in the product gas is much higher
takes place in the system. Hence, the final H2/CO ratio
than the optimum value for FT synthesis, so some type
is always less than 1.9, which requires gas composition
of H2 removal system is required to obtain the desired
adjustment before the FT reactor, as for the SMR pro-
synthesis gas composition. This inconvenience, the
cess. The noncatalytic process, used by Shell in their
need for external heating, and a high capital cost are
GTL process [Shell middle distillate synthesis (SMDS)],
the reasons that the SMR process is not recommended
takes place at very high temperatures (~1300–1400°C).
Catalytic POX, as the process used by ConocoPhillips,
operates at lower temperatures, but it is not proven for
industrial-scale GTL plants.
3. Autothermal reforming (ATR): ATR is the combination
of SMR and POX processes in the same reaction ves-
sel (Figure 11.29). This process allows the fine-tuning
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 11.27—Steam methane reformer. Figure 11.28—Noncatalytic POX.

AST-MNL58-11-0801-011.indd 277 3/12/13 2:18 PM

278 Petroleum Refining and Natural Gas Processing

process) or a bubbled fluid bed (advanced Synthol process),

and use iron catalysts.
As far as LTFT processes are concerned, technologies
can be classified into two main groups, depending on the
type of reactor used.
1. Fixed-bed reactors (FBRs): FBRs are operated with gas
recycle at moderate conversion per pass. FBRs are eas-
ily scalable and operated, but investment costs tend to
be higher. Heat removal and catalyst replacement are
other issues to be solved in a fixed-bed FT technology.
This reactor type is the option used by Shell (SMDS pro-
cess) and BP and by Sasol in the past (Arge technology).
2. Slurry bubble column reactors (SBCRs): Fine-powdered
catalyst is suspended in the liquid product wax, in which
Figure 11.29—Autothermal reformer. synthesis gas is bubbled. Reaction heat is removed
internally by cooling pipes immersed in the slurry. This
kind of reactor presents several advantages: the slurry
of the H2/CO product ratio to the required value for hydrodynamic regime allows for achieving an excellent
FT synthesis and eliminates the need of an external isothermal operation; the small solid particle size results
heat source. It is a catalytic process. An industrial ATR in good productivity, good interface contacting, and low
example is the technology provided by Haldor Topsøe pressure drop; and spent catalyst can be easily replaced
for the Oryx GTL plant (Sasol + Qatar Petroleum) in with fresh catalyst during normal operation. All of these
Qatar. Lurgi and Johnson Matthey also offer ATR units. features allow higher efficiencies than FBRs. However,
Other synthesis gas production processes exist that there exists little industrial experience with slurry reac-
consist of different arrangements of the previous three tors, so several issues need to be solved. Slurry reactors
basic options. An example is combined reforming, which are difficult to scale-up because their fluid dynamic
includes a SMR reactor and an ATR reactor (Figure 11.30). behavior is very complex. Catalyst attrition is another
Lurgi’s combined reforming is the option used by PetroSA common issue; attrition causes loss of catalytic mate-
in their high-temperature FT plants in Mossel Bay (South rial, makes solid-liquid separation difficult, and pro-
Africa) and by Methanex and BP at the Atlas methanol duces equipment erosion. Despite the technical issues,
plant in Trinidad and Tobago. this type of reactor has been selected by most of the
existing FT technologies: Sasol slurry-phase distillate
11.9.1.3.2 FT Technologies (SPD technology), ExxonMobil (AG-21 technology),
FT technologies can be classified in low-temperature ConocoPhillips, GTL.F1 (StatoilHydro-PetroSA-Lurgi),
(LTFT) and high-temperature (HTFT) processes. Nowa- Syntroleum, IFP-ENI, (joint development between the
days, the low-temperature option is the preferred one French Institute of Petroleum and ENI), Rentech, and
because of its improved economics and the high-quality the Japan Oil, Gas, and Metals National Corporation,
products that are obtained. to mention those who have reached at least a demon-
Two different high-temperature processes, developed stration scale. Other three-phase FT reactors have been
by Sasol in the 1990s, can be mentioned. Both are based proposed, such as the ebullating bed reactor (Petroleós
on fluidized bed reactors, either a circulating bed (Synthol de Venezuela, S.A.), or the advanced slurry reactor (BP),

Figure 11.30—Combined reformer.

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AST-MNL58-11-0801-011.indd 278 3/12/13 2:18 PM

Chapter 11 n Natural Gas Conditioning and Processing 279

but they are still at a pilot scale. All of them use cobalt- heated. A scavenging compressor may be needed to
based catalysts, except the Rentech process, which uses empty the vessel below the pressure of the pipeline. If
iron-based catalyst. previous refrigeration is used, unloading of the gas may
be done using a fluid displacement mechanism.
11.9.1.4 Product Upgrading Apart from ships, CNG transportation can also be
The raw product from FT reactors is a wax, solid at ambient made at a smaller scale by trains or trucks.
temperature, with a significant amount of olefins and some The arrival frequency of ships can be balanced with
oxygenates. Hence, hydrotreatment and hydrocracking storage at the delivery point. This storage can be onshore or
processes are required to obtain the desired final products, with an extra ship. CNG does not require large investments
mainly middle distillates. Available options are very similar in liquefaction or regasification capacity, although the ships
to those normally used in refineries, with some particulari- themselves are not cheap. It is generally accepted that CNG
ties due to the different nature of the feedstock. The higher provides a cost-effective way for a different distance/volume
molecular weight fraction of the FT wax is processed as in niche in comparison to LNG and pipeline gas transporta-
hydrocrackers and mild hydrocrackers. The lower molecu- tion. Typical cases in which CNG is supposed to be eco-
lar weight fraction is hydrotreated. Isomerization is also nomically competitive consist of transportation distances
desirable to improve cold properties because FT products from 800 km up to approximately 3000 km and natural gas
are highly paraffinic. If lubricants are to be obtained, isom- volumes of 200–600 MMscfd (5.7–17 × 106 m3).
erization and dewaxing processes are required; Chevron’s
Isodewaxing® is an example of such a process. Other com- 11.10.3 Advantages and Drawbacks
panies such as Shell, ExxonMobil, Axens, and Syntroleum Advantages:
also have specific processes for FT product workup. • Ecofriendly technology:
• The energy consumed is approximately one-half
11.10 Compressed Natural Gas that of the LNG chain, or one-eighth that of a GTL/
11.10.1 What Is CNG? methanol project.
In the gas processing industry, CNG is understood as natural • No “boil-off” losses
gas that has been compressed and is transported in pres- • Not a cryogenic liquid
sure vessels instead of traditional pipelines. CNG is a fea- • Flexibility:
sible transportation method to monetize associated gas or • Loading and unloading from offshore terminals is
stranded gas reserves and is a way to deliver gas to remote possible. Use of buoy system
markets. The term CNG is also used for the fuel of natural • Once the project reserves are depleted, the facili-
gas vehicles, but this product is out of the scope of this ties can be reused in a new project.
chapter. Hence, the CNG process described here exclusively • Easily scalable due to its modularity
refers to that applied for marine transportation of CNG. • CNG technology is relatively simple and most of the sys-
tem components can be designed using first principles.
11.10.2 CNG Chain Disadvantages:
The CNG chain can be divided into three main stages: • Unfeasibility of transporting either large gas volumes
compression, refrigeration, (depending on technology) or to long distances
and transportation; loading, journey, and unloading are • Ship CNG concept not commercialized to date (non
included in the transportation stage. proven technology)
• Compression: After a suitable gas treatment (mainly
dehydration to prevent freezing or hydrate formation) 11.10.4 CNG Technologies
to achieve the quality requirements demanded by the 11.10.4.1 Gas Transport Modules (GTM™15)
destination market, natural gas is compressed onshore. TransCanada uses GTM™ for CNG transportation, in which
The final pressure is set between 100 and 250 bar the gas is stored at 250 bar and ambient temperature.
(10,000 to 25,000 kPa), depending on the technology. In these modules, a high-strength composite material is
• Refrigeration: In some cases, the gas is cooled down applied to the external surface of a steel pressure vessel,
to –30°C after the compression to improve storage with a ratio of composite to steel that can vary depending
efficiency. on the application. GTM are approximately 35 % lighter
• Transportation: This stage is the most capital-intensive, than conventional all-steel CNG transportation alternatives.
requiring 85–90 % of the total capital of the chain [39]. GTM transportation can be performed on ships or barges.
It starts with the loading of the vessel (barge or ship) The maximum capacity envisaged for a GTM-based ship is
typically from a single point mooring (SPM) system, 1000 MMscf (28 × 106 m3 measured at standard conditions).
a jetty, or a submerged turret loading system (other With this concept, the facilities required for the loading and
configurations are possible; the final system selected unloading systems are simple and incorporate proven tech-
will depend on the sea states, availability of docking nology, very similar to that in use for 20 years on bulk CNG
facilities, and other local conditions). Once the load- trucking. Because ships operate at ambient temperature,
ing is complete, the vessel moves to the destination they require no complicated loading schemes or refriger-
terminal, where the unloading step takes place. Usually, ated hull. TransCanada has received the “Class Approval
the gas is to be delivered into a pipeline at a pressure in Principle” (AIP) by Lloyds Register for the use of GTM
ranging from 25 to 70 bar (2500 to 7000 kPa). The high- pressure vessels in ships (Figure 11.31) [40].
pressure gas in the vessels at the start of unloading
is let down across a valve to delivery pressure, which 15
GTM™: Manufactured under license from NCF Industries, Inc.,
causes a temperature drop and requires the gas to be to TransCanada, Calgary, Alberta, Canada.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`

Copyright ASTM International

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280 Petroleum Refining and Natural Gas Processing

11.10.4.3 Volume Optimized Transport and

Storage (VOTRANS™17)
EnerSea developed the VOTRANS™ concept, in which the
natural gas is compressed, cooled, and then stored in a
series of API carbon-steel pipes that can be stacked horizon-
tally or vertically. The innovations introduced by VOTRANS
include a 60–100 % increase in the gas that can be stored per
unit of containment steel, along with a 10–20 % increase in
the quantity of gas cargo that can be cost-effectively evacu-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

ated from the CNG storage system, compared with conven-

tional CNG concepts (nonrefrigerated). It is claimed that
this performance is made possible by optimizing the stor-
age conditions (temperatures of –17 to 4ºC and pressures
of ~100 bar) and using their proprietary gas-loading and
discharging processes [43]. The VOTRANS vessel design
has achieved AIP from ABS (Figure 11.33) [44].
EnerSea offers ship or barge-based systems. The rel-
evant variables to specify for a specific project are gas flow
rate, distance from supply to market, and terminal avail-
ability. Ranges for rates and distances are:
• Ship: 70 to ≥500 MMscf/day (2 to ≥14 × 106 m3/day) of
gas and 135 to ≥2700 nautical miles (250 to ≥5000 km)
• Barge: 10–75 MMscf/day (0.3–2.1 × 106 m3/day) and 50
to ≥500 nautical miles (92 to ≥926 km).
Figure 11.32—Sea NG ship with Coselle. Source: Image
EnerSea has also a specific concept for onshore CNG
courtesy of Sea NG Corporation.
storage called VOLANDS™18 (Volume Optimized Land
Storage), which improves the reliability of supply and is
11.10.4.2 Coselle™16 intended to be used as a buffer to manage market demand
Sea NG uses the Coselle concept, which consists of high- fluctuations.
strength steel pipe coiled on a carousel permanently
installed in the ship [41]. Each Coselle has approximately 10 11.10.4.4 Fibre Reinforced Plastic
mi (16 km) of pipe, with a diameter of 6/8 in. (152/203 mm), (FRP™19) Vessels
and can store up to 3.6 MMscf (0.1 × 106 m3 measured at Trans Ocean Gas proposes the use of FRP pressure vessels
standard conditions) of gas at 250 bar and ambient tem- supported vertically in a lightweight steel frame called a cas-
perature. Coselles are carried in stacks within the ship’s sette. It is a system with references in critical applications
hold, which is 520 MMscf (14.7 × 106 m3), the maximum such as aerospace, national defense, and public transport
capacity of a Coselle-based ship (see Figure 11.32). Because industries. By using a combination of pressure and low
the Coselles have a large storage capacity, only a relatively temperature, natural gas is efficiently stored in FRP pressure
simple manifold with few valves and controlling systems vessels. These vessels get stronger at low temperature (they
are required. Some of the advantages of Coselle over bottles resist up to –100°C), so they are ideal for chilled CNG storage.
are lower cost, safer (lower probability of failure and lower Some of the advantages of this system are light weight (one
consequence of failure), faster to manufacture, and more third that of steel), corrosion resistance, safety, and reliability
reliable gas handling. The 50-MMscf (1.42 × 106 m3) ship [45]. FRP vessels can be outfitted on ships or barges, and the
from Sea NG has full approval for construction from the storage capacity of the carriers can reach 1000 MMscf (28 ×
American Bureau of Shipping (ABS) [42]. 106 m3) (see Figure 11.34).

17
VOTRANS™ belongs to EnerSea, Houston, Texas, USA.
18
VOTRANS™ belongs to EnerSea, Houston, TX.
Coselle™ belongs to Sea NG Corporation, Calgary, Alberta,
16 19
FRP™ belongs to Trans Ocean Gas, St. John's, Newfoundland
Canada. and Labrador, Canada.
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Chapter 11 n Natural Gas Conditioning and Processing 281

Figure 11.33—EnerSea’s CNG barge and ship (VOTRANS). CNG can be delivered using EnerSea’s VOTRANS CNG marine service with
ships (right) or barges (left) as shown in the illustration.

By definition, the initial marine CNG applications

will not be commissioned in areas where “conventional”
gas transport options can be economically applied. Proj-
ect developers must be prepared to share risk to obtain
first mover advantage. Introduction of natural gas sup-
ply through marine CNG involves risk for the consuming
nation—security of supply, technology uncertainty, and
reliability. Hence, work with governments/consumers is
needed to address real and perceived risks [48].

11.11 Natural Gas Hydrates

11.11.1 Overview
Water can combine with low-molecular-weight natural
gases to form a solid hydrate, even if the temperature is
above the water freezing point. Hydrates have the property
to concentrate hydrocarbons; in other words, the volume of
a given gas hydrate is much less than the normal volume of
the gas from which the hydrate is formed.
Figure 11.34—Trans Ocean Gas CNG ship (FRP). Source: Picture
The natural gas hydrate (NGH) chain is a technology
courtesy of Trans Ocean Gas, Inc.
option for transportation and storage of natural gas [20].
The gas volume content of hydrates is approximately 180
11.10.4.5 Pressurized Natural Gas (PNG®20) times that of natural gas at standard conditions. They
Knutsen is a shipping company that proposes the use of a require moderate cooling to be produced, and once pro-
technology called PNG (Figure 11.35). It consists of steel duced, they are stable at atmospheric pressure and rela-
cargo containment cylinders, with a diameter of 42 in. tively mild temperatures, in the range of –5 to –15°C. The
(1.07 m) each, packed vertically in a composite shelter. This disadvantage is that for each mole of gas, there are approxi-
shelter has the following advantages: light weight, resis- mately six moles of water being transported.
tance to fire, and resistance to heat variations. The gas is The following section provides a general overview about
stored at 250 bar (25,000 kPa) and ambient temperature, what a gas hydrate is and describes the NGH chain as an

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
so no insulation is required to prevent heating during the opportunity for transportation and storage of natural gas.
voyage [46]. This containment system can be used in vessels
ranging from 60 to 1000 MMscf (1.7–28 × 106 m3). Regard-
ing certification, the PNG containment tank has received an
approval by Det Norske Veritas (DNV).

11.10.4.6 CNG Commercialization

The marine CNG business has the potential to be a multibillion
dollar business, although there are no large-scale commercial
CNG projects yet (2011). Technology developers have spent
several years to fully engineer the designs into a commercial
product, get classification approval, and build physical proto-
type models of the containment systems and functional pro-
cess systems for the testing [47]. As a consequence, advances
in marine CNG transport systems have been truly remarkable;
there are arguably three to four competing systems developers
ready to make a commercial commitment.

Figure 11.35—Knutsen CNG ship (PNG). Source: Picture

20
PNG® belongs to Knutsen, Haugesund, Norway. courtesy of Knutsen.
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282 Petroleum Refining and Natural Gas Processing

The major stages involved in this chain (Figure 11.38)

are the manufacture of NGHs from natural gas and water,
transportation of hydrates by ship, and regasification (or
dissociation to natural gas and water) at the point of use.
Two different concept technologies are under development:
dry hydrate and slurry hydrate. The slurry hydrate con-
cept includes two different particular processes: the slurry
water-based hydrate and the slurry oil-based hydrate
processes. The application of each process is foreseen as
follows:
• The dry hydrate process, where natural gas is con-
verted to solid hydrates and transported at atmospheric
pressure in bulk carriers.
• The slurry water-based hydrate process, where natural
gas is converted to solid hydrates and transported as a
concentrated water hydrate slurry in a shuttle tanker
at low pressure.
• The slurry oil-based hydrate process, where natural gas
Figure 11.36—NGH (laboratory manufactured) [20]. Source:
Picture courtesy of Calogero Migliore. is converted to solid hydrates and transported together
with crude oil/condensate as a slurry in a shuttle tanker
at low pressure.
11.11.2 What Is a Gas Hydrate?
Gas hydrates are crystalline “ice-like” solids (see Fig-
ure 11.36), one form of the chemical inclusion compounds 11.11.3.1 The Dry Hydrate Process
known as clathrates. Clathrates are nonstoichiometric com- The dry hydrate process is an option to store and trans-
pounds in which guest molecules are entrapped in a cage port significant volumes of natural gas in the form of
structure composed of host molecules. There is no chemical solid hydrate at atmospheric pressure in competition with
bond between the guest and host molecules. The crystal CNG technology. Natural gas could be converted into solid
lattice is made of hydrogen-bonded molecules. NGHs exist hydrate and then conveyed to bulk carriers. The bulk carri-
because of the ability of water molecules to form a lattice ers take the solid hydrate to distant gas markets where the
structure through hydrogen bonding. The water molecules hydrate is melted and the gas is recovered and transferred
are oriented such that they build a sharing-faces polyhe- to the final user.
dron. The cages are stabilized by the van der Waals forces The dry hydrate process basically consists in three
between the water and the enclathered gas molecule [49]. main stages: dry hydrate production, dry hydrate ship-
Figure 11.37 shows a schematic representation of a cage ping, and dry hydrate regasification (dissociation) [50].
with methane as a guest molecule. Figure 11.39 shows a simplified diagram of the dry hydrate
production process.
11.11.3 NGH Chain For dry hydrate production, gas from a gas processing
The use of gas hydrate technology for the transportation facility passes through a set of continuous stirred tank reac-
and storage of natural gas is seen as an opportunity for tors, operating in the range of 50–90 bar (5000 to 9000 kPa)
the gas industry to develop the NGH chain. The interest is and 10–15°C, where it reacts with water and is converted
based on the energy content of the hydrates because their to hydrates. Because the reaction is exothermic, energy is
volume is much smaller than the normal volume of the gas released (~410 kJ/kg). This heat is removed from the system
from which the hydrate is formed. NGHs might contain a to keep the reactor at constant temperature [51].
theoretical maximum of approximately 180 m3 standard of Hydrate shipping is carried out using standard ships.
gas per cubic metre of hydrate; in other words, 180 m3 of Experimental studies have shown that NGHs remain stable
natural gas at standard conditions are released when melt- at atmospheric pressure when kept frozen in the range of
ing 1 m3 of NGHs. –5 to –15°C at adiabatic conditions; therefore, shipping is
at atmospheric pressure and –15°C. These storage condi-
tions are possible because of the metastability property of
Water molecules hydrates [52].
Hydrogen bonded
cage Regasification takes place by melting hydrates with
warm water in direct contact. Natural gas and water are
then separated. Gas is compressed and dehydrated before
being sent to the final user or to a distribution system
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

(see Figure 11.40). The separated water is a combina-

tion of the water carried by the hydrates and the water
Methane used for melting. The same amount of water carried by
molecule hydrates is loaded back to the ship and shipped back to
the production plant for its use in the manufacturing of
the hydrates. This water contains seeds of hydrate crys-
Figure 11.37—Representation of the 512 cage with methane as tals that facilitate reaction rates in the hydrate produc-
a guest molecule. tion process [52].
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Chapter 11 n Natural Gas Conditioning and Processing 283

Feed gas Storage &

Hydrate Shipping Customers
Manufacture Re-gasification

Water

Figure 11.38—Block diagram of the major stages of the NGH chain.

Figure 11.39—Simplified diagram of the dry hydrate production process. Source: Figure courtesy of GL Industrial Services, UK,
Ltd. (formerly Advantica, Ltd.).

Gas to transmission/
Gas Dewatering distribution
system
Booster
Compressor

Water

Hydrate ship

Hot water boiler

Heat

Hot water

Figure 11.40—Simplified diagram of the hydrate regasification (dissociation) process. Source: Figure courtesy of GL Industrial
Services UK, Ltd. (formerly Advantica, Ltd.).

11.11.3.2 The Slurry Water-Based Hydrate reinjecting the gas to enhance oil recovery is increasingly
Process being questioned because the potential revenues of the gas
The slurry water-based hydrate process could provide a are not achieved.
technology solution to monetize offshore associated gas, The slurry water-based hydrate production process
where reserves are too small to justify a gas pipeline. Flar- is a simplification of the dry process in which the water
removal stage consists of just the bulk separation stage.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

ing is no longer an option and the conventional practice of

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284 Petroleum Refining and Natural Gas Processing

The partial dewatering produces concentrated but pump- [6] Eckersley, N., and Kane, J.A., “Designing Customized Desul-
able hydrate slurry containing at least 75 volumes of gas furization System for the Treatments of NGL Streams,” paper
presented at the Laurance Reid Gas Conference, Norman,
per volume of hydrate. The hydrate is then transferred OK, 2004.
to a shipping vessel, at approximately 10 bar (1000 kPa) [7] Leeper, J.E., “Mercury—LNG’s Problem. Under Some Con-
and 2–3°C to be transported to the customers [51]. At the ditions Mercury Can Be a Major Source for Concern in
receiving terminal, the hydrate slurry is heated to dissocia- LNG Processing,” http://www.calgoncarbon.com/documents/
tion and then follows the same path as in the dry hydrate Mercury-LNGsproblem.pdf.
regasification process. [8] “Nitrogen Rejection/Helium Recovery Units,” Chicago
Bridge & Iron Company, http://www.cbi.com/services/nitrogen-
rejection-helium-recovery.aspx.
11.11.3.3 The Slurry Oil-Based Hydrate [9] Gas Processors Suppliers Association Engineering Data Book,
Process 12th ed., Gas Processors Suppliers Association, Tulsa, OK, 2004.
The niche of application of the slurry oil-based hydrate tech- [10] Mokhatab, S., Poe, W.A., and Speight, J.G., Handbook of
nology would be the same as the slurry hydrate water-based Natural Gas Transmission and Processing, Gulf Professional
Publishing, London, 2006.
technology—to capture and handle offshore associated gas
[11] “Twister Supersonic Separator,” http://twisterbv.com/products-
where the reserves are too small to justify a gas pipeline. services/twister-supersonic-separator/.
In the slurry oil-based hydrate process, the hydrate reac- [12] Bloch, H., and Soares, C., Turboexpanders and Process Applica-
tor consists of a cooling unit, where gas reacts with water tions, Butterworth-Heinemann, Woburn, MA, 2001.
to produce hydrates. The resulting NGHs are then mixed [13] Jibril, K., Al-Humaizi, A., Idriss, A., and Ibrahim, A., “Simula-
with refrigerated crude oil or condensate to make oil-based tion Study Determines Optimum Turboexpander Process for
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slurry. The oil-hydrate slurry is stored at –10°C and at pres-
[14] “NGL Extraction Technologies,” PERP Report, NEXANT
sure close to atmospheric [53]. The transportation of the Chem Systems, San Francisco, CA, 2007.
slurry to shore can be in an isolated low-pressure shuttle [15] Hagyard P., Paradowski H., and Gadelle D., “Simultaneous
tank or under pressure using a pipeline. At the receiving ter- Production of LNG and NGL,” 2004, http://www.ivt.ntnu.no/
minal the slurry is sent to the recovery process, where it is ept/fag/tep4215/innhold/LNG%20Conferences/2004/Data/
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[16] Coyle, D., de la Vega, F.F., and Durr, C., “Natural Gas
ration unit. The recovery process produces water-saturated Specification Challenges in the LNG Industry,” 2004, http://
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Natural-Gas-Specification-Challenges-in-the-LNG-Industry
ACKNOWLEDGMENTs .pdf.
The coordinating author acknowledges the following col- [17] Chiu, C.H., “LPG Recovery in Baseload LNG Plant Exam-
ined,” Oil Gas J., Vol. 95, 1997, pp. 59–63.
leagues from the LNG Technology Group at Repsol’s [18] Elliot, D., Qualls, W.R., Huang, S., Chen, J.J., Lee, R.J., Yao,
Technology Center who contributed to the writing of this J., and Zhang, Y., “Benefits of Integrating NGL Extraction
chapter: Eduardo Carbón, Roberto Coll, Eduardo Machado, and LNG Liquefaction Technology,” paper presented at the
Julieta Maresca, Silvia Pérez, José Luis Rivas, and Cristina American Institute of Chemical Engineers, Spring Meeting,
Tubilleja. Each of them in their area of expertise contrib- Cincinnati, OH, 2005.
[19] Attaway, D.A., Huang, S., Kotzot, H., and Durr, C.A., “Optimal
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to include the updated situation of each element of the presented at the AIChE Spring Meeting, Atlanta, GA, 2005.
natural gas value chain. Special thanks to Mar González, [20] Migliore, C., “Design and Economic Analysis of the Hydrate

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
from Repsol’s corporate head office, who kindly helped to Technologies for Transportation and Storage of Natural Gas,”
organize and manage the permissions for reprint required M.Sc. Dissertation, University of Salford, United Kingdom, 2003.
to complete the writing of this chapter. Furthermore, we [21] “Fuel Switching with NGLs/Small Scale LNG,” PERP 04/05S1,
Nexant Chem Systems, San Francisco, CA, 2005.
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www.tokyo-gas.co.jp/lngtech/ug-tank/index.html. shop on Methane Hydrates R&D, Washington, DC, 2002.
[39] Deshpande, A., and Economides, M.J., “CNG: An Alterna- [51] Fitzgerald, A., and Taylor, M., “Offshore Gas-to-Solids Tech-
tive Transport for Natural Gas Instead of LNG,” University nology,” SPE 71805, paper presented at the Offshore Europe
of Houston, SPE Gulf Coast Section, http://www.spegcs.org/ Conference, Aberdeen, Scotland, 2001.
attachments/studygroups/6/CNG-An_Alternative_Transport_ [52] Gudmundsson, J.S., Hveding, F., and Børrehaug, A., “Trans-
for_Natural_Gas.pdf. port of Natural Gas as Frozen Hydrate,” paper presented at
[40] http://www.transcng.com/home. the 5th International Offshore and Polar Engineering Confer-
[41] http://www.coselle-system.com/overview. ence, The Hague, The Netherlands, 1995.
[42] “Sea NG Ships, Key Features,” http://www.coselle-system.com/ [53] Gudmundsson, J.S., Andersson, V., Levik, O.I., and Parlak-
coselle-ship. tuna, M., “Hydrate Concept for Capturing Associated Gas,”
[43] Dunlop, J., “EnerSea CNG System Offers Valuable Gas Deliv- SPE 50598, paper presented at the SPE European Petroleum
ery Solution,” Energy Tribune, 2007, USA, http://www.energy Conference, The Hague, The Netherlands, 1998.
tribune.com.

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12
Hydrogen Management
N. Zhang1 and F. Liu2

12.1 Introduction one rejects carbon from petroleum streams (e.g., fluid
The concern of hydrogen balance has increased over the last catalyst cracking and delay coking) and the other adds
15 years. Haun et al. [1] recollected the history of the hydrogen hydrogen (e.g., residue hydrotreating and hydrocracking).
issue in refining. During the early age of oil refining, refiners Although the latter is much more expensive in capital and
paid little attention to hydrogen production, consumption, operating cost than the former [3], it is still predictable
or distribution among the products. By the mid-1950s, after that hydrocracking processes will play the main role in the
the prevalent use of catalytic reforming, refiners had a cheap heavy-end conversion because of their considerable flexibil-
hydrogen resource that could be used as a reagent in their ity of the feedstock, processability of the yields, and quality
refining schemes. The hydrogen supply generally exceeded of the products. Especially when a refinery processes sour
the demand. Although hydrogen became more and more feedstock, the poor product quality after “carbon-reject”
important in improving process performance, hydrogen man- processes causes further problems in product blending
agement was of little importance in refineries. and requires extra hydroprocessing. Available processes
Hydrogen availability becomes a focal point because for heavy crude upgrading are compatible and can be
refiners are facing challenges of stringent environmental integrated to achieve the optimal economic results [4].
regulations and increasing demand of transport fuel. Along Generally, the additional “on-purpose” hydrogen capacity is
with the legislation of environmental protection, tougher required if the hydrocracking process is implemented.
gasoline and diesel quality specifications in the European Many efforts have been contributed to analyze how
Union and the United States have been implemented to these impacts affect hydrogen balance in refineries. Haun
reduce smog-forming and other pollutants in automotive et al. [1] looked at the amount of hydrogen presented in the
exhaust. Such a trend can be clearly foreseen in the near feedstock versus the amount in the desired product slate as
future. For example, the gasoline fuel specifications in the ultimate determinant of the hydrogen balance problem.
the European Union decreased the maximum sulfur from The impact of the refinery evolution from hydroskimming to
150 ppm to 10 ppm before 2009, and the maximum aro- complex conversion is illustrated by comparing the hydrogen
matics from 42 % vol to 35 %, while the maximum sulfur content in feeds and products. Two upgraded hypothetical
in diesel fuel specifications decreased from 350 ppm to refineries—gasoline refinery and diesel refinery—were inves-
10 ppm. To stay in business, one of the options for refiners is tigated. The case studies show that modern refineries can
to switch their feedstock to light sweet crude if they believe not only achieve anticipated product specifications but also
such supply is ample and under a decent price in the future. dramatically improve their profitability. However, the hydro-
At the same time, they must look at a significant invest- gen requirement is also largely increased. For the gasoline
ment in desulfurization. Lower-sulfur fuel means more refinery, the hydrogen from catalytic reforming cannot supply
hydrogen is necessary for deeper hydrodesulfurization. In sufficient hydrogen, and hydrogen has to be recovered from
the meantime, lower aromatic gasoline specifications will other refinery off-gases to settle the hydrogen balance. For
decrease the operation severity in catalyst reformers, lead- the diesel refinery, hydrogen has to be produced through a
ing to reduction of the byproduct hydrogen (Table 12.1). hydrogen plant. Hydrogen management becomes essential for
Another future environmental effect is that the legislation profitable operations in upgraded refineries. Lamber et al. [5]
of greenhouse gas abatement may urge refineries to reduce analyzed how the environmental impacts on product qualities
hydrogen production. and changes in product slates shifted the hydrogen balance in
Other big effects on the refinery hydrogen balance are refineries. It can be seen from Table 12.3 that vacuum distil-
caused by bottom-of-barrel upgrade. According to more late and residue hydroprocessing provide the main incentive
and more strict limitation of pollutant emissions, the mar- for hydrogen demand. Heavy-end gasification is suggested as
ket share of fuel oil has declined for a long period. On the an attractive option complying with the hydrogen demand,
other hand, the market trends indicate a very large increase residue disposal, and clean energy requirement of refineries.
in the share of middle distillates, reflecting spectacular Philips [6] discussed the approach to find the optimal
growth in diesel oil and jet fuel production (Figure 12.1) [2]. hydrogen scenarios from the engineering point of view. An
Although crude is expected to become heavier and con- example project shows that through hydrogen manage-
tain more sulfur (Table 12.2), the refiners are pressured to ment, hydrogen production capacity is decreased, resulting
add more conversion capacity to be competitive. not only in a reduction in capital and operating expense but
There are two different kinds of processes to increase also in a significant decrease in carbon dioxide (CO2) emis-
the hydrogen-to-carbon ratio in the refinery product slate: sions. However, it has been pointed out that any hydrogen
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1
The University of Manchester, Manchester, UK
2
British Petroleum Plc., Beijing, China
287
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288 Petroleum Refining and Natural Gas Processing

Table 12.1—EU Gasoline and Diesel Table 12.2—U.S. Crude Characteristics

Regulations Year API Gravity Sulfur (wt %)
EU - MOTOR GASOLINE REGULATIONS
1990 31.86 1.10
2003 2005 2009 2012
1992 31.32 1.16
Sulfur, ppm (max) 150 50/10 10 10
1994 31.39 1.14
Benzene, % vol (max) 1 1 1 1
1996 31.14 1.15
Aromatics, % vol 42 35 35 35
1998 30.98 1.31
(max)
2000 30.99 1.34
Olefins, % vol (max) 18 18 18 18
2002 30.42 1.41
EU - ON-ROAD DIESEL REGULATIONS
2004 30.18 1.43
2003 2005 2009 2012
2006 30.44 1.41
Sulfur, ppm (max) 350 50/10 10 10
2008 30.21 1.47
Density (max) 0.845 0.845 0.845 0.845

Distillation T95, degC 360 360 360 360 (CH4), saturated liquefied petroleum gas (LPG), straight-
(max) run naphtha, and some refinery off-gases. The management
Cetane index (min) 46 46 46 46 of hydrogen generation and hydrogen recovery depends on
the refinery hydrogen balance, raw material prices, fuel
Cetane number (min) 51 51 51 51
prices of hydrogen generation, total operating cost, and
investment incurred.
solution must be tested not just for economic viability, but Hydrogen generation processes in a refinery are steam
the technical robustness, refinery integration, and con- reforming and partial oxidation. Gardner [7] addressed the
structability should also be taken into account. distinguishable factors of hydrogen generation processes.
For gaseous feedstock, the capital costs inside battery lim-
12.2 Hydrogen Production Processes its for steam reforming and partial oxidation are similar.
When hydrogen consumers with large hydrogen require- However, the high-pressure oxygen requirement adds extra
ment (e.g., hydrocrackers) are operating in a refinery, the expense to partial oxidation. For heavy feedstock, the capital
supplemental hydrogen often needs to be provided by cost for partial oxidation is significantly higher than for gas-
hydrogen generation processes other than catalytic reform- based steam reforming because of the requirement for
ing units. To produce hydrogen by a steam reforming pro- sulfur removal and feedstock handling facilities. Except for
cess, the available feedstock in a refinery can be methane the facts that gaseous feedstock is extremely expensive and

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Figure 12.1—The growing consumption of light and middle distillates [2].
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Chapter 12 n Hydrogen Management 289

hydrogen cost, or vice versa. However, hydrogen plants with

Table 12.3—Typical Hydrogen Consumption; PSA become a preferred choice for hydrogen generation in
Data Chemical Consumption Only refineries nowadays for the following reasons:
Percent Percent • Hydrogen purity has significant effects on the design
Weight on Weight on and operation of hydroprocessors. High purity is favor-
Process Feed Crude
able to hydroprocessor design [8].
HT Straight run naphtha 0.05 0.01 • The state-of-art PSA technology provides high hydro-
HT FCC/TC naphtha 1 0.05–1 gen recovery up to 90 % [9], which enormously reduces
hydrogen cost.
HT kerosene 0.1 0.01–0.02
• A PSA process is easier to design and operate for a
HDS LS gasoline to 0.2 % S 0.1 0.03 large-scale hydrogen plant than an adsorption process
HDS HS gasoline to 0.2 % S 0.3 0.04 that normally uses packing columns.
HDS LS gasoline to 0.05 % S 0.15 0.04 A hydrogen plant with PSA has low turndown ratio,
high operation flexibility, modest control, short startup and
HDS HS gasoline to 0.05 % S 0.35 0.05
turndown periods, long-term operation, and relative ease
HDS FCC/TC gasoline 1 0.1 of expansion.
Cycle oils hydrogenation 3 0.3 The process description for a hydrogen plant with
Hydrocracking VGO 2-3 0.5–0.8 PSA (process flow diagram Figure 12.2 shows a top-fired
reformer) is as follows:
Deep residue conversion 2-3.5 1–2
• The feedstock combined with recycled hydrogen is
Data from Lamber et al. [5]. HT, hydrotreating; FCC, fluid catalytic preheated in the convection section of the reformer.
cracking; HDS, hydrodesulfurization; VGO, vacuum gas oil.
The preheated hydrocarbon feed is routed to the sulfur
absorber, where unsaturated hydrocarbons are hydro-
heavy feedstock is very cheap, high capital cost for partial genated and organic sulfur (mercaptans) is converted
oxidation processes plus oxygen supply requirements make to hydrogen sulfide (H2S) in the first catalyst bed of
the hydrogen cost substantially higher than that from cobalt molybdenum oxide. H2S is removed from the
steam reforming processes. Because of the capability to feed gas in the second bed of zinc oxide.
handle heavy feedstock, a partial oxidation process is an • The desulfurized feed is then mixed with superheated
opportunity to overcome bottom-of-barrel problems in high-pressure steam and preheated in the convection
refineries, whereas the amount of available heavy feedstock section of the reformer. The mixed feed enters the radi-
in a refinery typically far exceeds the required amount to ant section of the reformer and flows down through
satisfy the hydrogen balance. Therefore, alternative con- catalyst-filled tubes, where it reacts to produce hydro-
sumers of hydrogen or synthesis gas must be found to make gen gas (H2), CO, CO2, and CH4.
this option viable. Steam reforming currently dominates • Combustion air and convection-section flue gases are
the hydrogen generation processes in refineries. moved through the reformer by the flue gas fan.
• The reformer effluent is routed through the waste
12.2.1 Steam Reforming heat boiler, where the recovered heat is used to gen-
There are two typical processes in steam reforming with dif- erate high-pressure saturated steam and feed to the
ferent purification processes. In conventional processes, the high-temperature shift converter, where excess steam
low-temperature shift reactor is necessary to reduce resid- converts most of the CO to CO2 and H2 over a bed of
ual carbon monoxide (CO) in synthesis gas further after catalyst. The shifted gas is cooled in a heat exchanger
the high-temperature shift conversion. The product is then train, which generates high-pressure steam and pre-
cooled and scrubbed with circulating amine or hot potas- heats boiler feed water (BFW). Condensed water from
sium carbonate solution to remove CO2 by absorption. The the gas cooling is removed in a knockout drum.
remaining small quantities of CO and CO2 are converted to The raw hydrogen stream is purified to produce
CH4 by methanation. The hydrogen purity in the conven- high-purity hydrogen by a PSA unit, where impurities are
tional processes is typically 95–97 %. The impurities are removed by a cyclic adsorption process. The tail gas stream
mainly CH4 and carbon oxidant at parts per million levels. from the PSA unit, containing the removed impurities and
Pressure swing adsorption (PSA) was introduced as a some residual hydrogen, is returned to the reformer as fuel
replacement of the conventional purification process in the gas. A hydrogen product purity of more than 99.9 vol % can
1970s. The high-temperature shift gas is cooled and puri- be achieved through PSA.
fied by PSA. The hydrogen purity by PSA purification can Process description for a conventional hydrogen plant
reach more than 99.9 %. The residue of PSA is recycled to (process flow diagram Figure 12.3 shows a side-fired
the reformer as fuel. Because a part of generated hydro- reformer) is as follows:
gen is discharged as residue in PSA, the hydrogen yield of • The feedstock combined with recycled hydrogen is
unit feedstock with PSA is lower than with conventional preheated in the convection section of the reformer.
processes but needs less external fuel. The investment of The preheated hydrocarbon feed is routed to the sulfur
hydrogen plants with PSA is higher than the conventional absorber, where unsaturated hydrocarbons are hydro-
plants with regards to the same hydrogen production. The genated and organic sulfur (mercaptans) is converted
economics of hydrogen generation depend on the price of to H2S in the first catalyst bed of cobalt molybdenum
feedstock and fuel. Whereas feedstock is expensive and fuel oxide. H2S is removed from the feed gas in the second
is relatively cheap, the conventional process shows lower bed of zinc oxide.
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290 Petroleum Refining and Natural Gas Processing

Figure 12.2—Process flow diagram of a hydrogen plant with PSA.

• The desulfurized feed is then mixed with superheated being used for the process. The remaining steam is
high-pressure steam and preheated in the convection exported after superheating.
section of the reformer. The mixed feed enters the radi- The pretreated feedstock is mixed with superheated
ant section of the reformer and flows down through steam and preheated to 500°C (932°F) before passing to
catalyst-filled tubes, where it reacts to produce H2, CO, the radiant section of the reformer. The steam reforming
CO2, and CH4. reaction takes place in the furnace tube packed with nickel-
• Combustion air and convection-section flue gases are based catalyst. The steam reforming reaction is not just
moved through the reformer by the flue gas fan. one reaction but can be described briefly by the following
• The reformer effluent is routed through the waste equations:
heat boiler, where the recovered heat is used to gen-
erate high-pressure saturated steam and feed to the CH4 + H2 O ⇔ CO + 3H2 − ∆H (12.1)
high-temperature shift converter, where excess steam
m (12.2)
converts most of the CO to CO2 and H2 over a bed of Cn Hm + nH2 O ⇔ nCO + ( n + )H2 − ∆H
catalyst. After recovering the heat from this stream, 2
the effluent is routed to the low-temperature shift CO + H2 O ⇔ CO2 + H2 + ∆H (12.3)
converter to further reduce the level of CO. The shifted
gas is cooled in a heat exchanger train, which generates Although the reactions in equations 12.1 and 12.2 are
high-pressure steam, preheats BFW, and provides heat- endothermic and the reaction in equation 12.3 is exother-
ing duty to the reboiler for the regenerator within the mic, the overall reaction is highly endothermic. The burn-
CO2 scrubbing package. ers in the furnace radiant section provide heat to maintain
• The product is then cooled and scrubbed with circu- the operating temperature of steam reforming at approxi-
lating hot potassium carbonate solution to remove mately 850°C (1562°F). Addition of excess steam not only
CO2 by absorption. The raw hydrogen stream is puri- shifts the reaction equilibrium to produce more hydrogen
fied by converting the remaining CO and CO2 to CH4 but also avoids carbon formation in catalyst. However, high
through the methanator. The hydrogen product purity steam import increases the duty of a steam reformer.
is approximately 95–97 vol %. Low operating pressure promotes hydrogen genera-
• Condensed water from the gas cooling is removed in tion, but most hydrogen plants with PSA operate above
the knockout drums. 20 atm (294 psi) on the basis of the consideration of the
• BFW is preheated by shifted gas before feeding to the optimum PSA operating pressure, compression cost, and
steam drum. High-pressure steam is generated by the equipment size.
waste heat boiler reformer convection section and by
exchanging heat with shifted gas. 12.2.2 Reformed Gas Shifting
• Saturated steam is drawn from the steam drum and The temperature of the gases exiting from a reformer is
superheated in the reformer convection section before reduced to 340–360°C (644–680°F) by generating steam.
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Chapter 12 n Hydrogen Management 291

Figure 12.3—Process flow diagram of a conventional hydrogen plant.

CO is converted further to hydrogen in a high-temperature 12.2.5 Gasification

shifting reactor on magnetite iron oxide-based catalyst. Partial oxidation plants are capable of processing a wide
Equation 12.3 shows the reaction procedure. Normally, a variety of feedstocks, including
low-temperature shifting reactor is only used in the con- • Gas (natural gas, refinery off-gas)
ventional processes. • Heavy residue (vacuum residual, fuel oil, asphalt)
The gases exiting from the shifting reactor are cooled in • Petroleum coke
stages to generate steam and preheat BFW. They are finally The partial oxidation reaction proceeds as follows:
cooled by air and water to normal temperature (40°C, or
104°F). The gases are then purified by PSA. The condensed CnHm + (n/2)O2 → nCO + (m/2)H2 – ΔH (12.4)
sour water is recycled to the boiler after stripping.
The term of “partial oxidation” may be replaced by
12.2.3 PSA and Fuel System “gasification.” The reaction involves the combustion of a
The process characteristics of PSA are discussed in Section hydrocarbon in a flame with less than stoichiometric quan-
12.2.1. The adsorption forces for the components in the shift tities of oxygen to form CO2 and steam, which, in turn, react
gas are water >> CO2 > CO > CH4 > hydrogen on the mol- with the unreacted hydrocarbon to produce CO and hydro-
ecule sieve adsorbent. The product of PSA is hydrogen at gen. The overall reaction remains exothermal.
more than 99.9 %. The impurities in the product are mainly Various secondary reactions including hydrocracking,
CH4 with carbon oxides at part-per-million levels. The rest the steam carbon reaction, hydrocarbon reforming, and the
of the components appear in the residue. Because the dis- water-gas shift reaction also take place.
charge pressure of PSA is very low (approximately 1.5 atm
or 22 psi) to achieve high hydrogen recovery, the residue 12.2.6 Hydrogen Production from
from PSA is directly sent back to the steam reformer with Nonhydrocarbon Sources
specific low operating pressure burners as fuel instead of Steam reforming and partial oxidation/gasification pro-
compressing to a fuel system. duce hydrogen mainly from fossil fuels, which is one of the
The additional fuel is supplied by a refinery fuel sys- major CO2 emission sources in oil refineries. Because of
tem. The mixture of fuel gas is mixed with air preheated in growing concerns over greenhouse gas emissions in indus-
the convective section of the reformer furnace and sent to try, there is a strong interest to exploit nonhydrocarbon
burners in the radiant section. The high-temperature flue hydrogen sources. Some potential hydrogen sources can be
gas enters the convention section, heats the reformer feed, summarized as follows:
superheats the exporting steam, generates steam, and sepa- • Electrolysis of water: Production of hydrogen from
rately heats combustion air. water using electrolysis can be done on an industrial
scale. However, it requires a large amount of energy.
12.2.4 Steam Generation System Usually the electricity consumed is more valuable than
Hydrogen plants with steam reforming generate steam to the hydrogen produced. Therefore, it is uncompetitive
supply the reaction and recover energy. BFW is pumped with the hydrogen production from coal or natural
and preheated by the shift gas before entering the boiler. gas. Nevertheless, this option may become attractive if
The steam generation is completed by exchanging heat with hydrogen is used as a media to store renewable electric-
the reformed gas, the shift gas, and the flue gas. The steam ity in the future.
generated in a hydrogen plant is always more than the reac- • Thermolysis of water: Water is spontaneously discom-
tion requirement. The extra is exported to a refinery steam posed at approximately 2500ºC. However, such a tem-
system after superheating. --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- perature is simply too high for usual process piping
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292 Petroleum Refining and Natural Gas Processing

and equipment, which makes any potential industrial- 12.3.1 Pressure Swing Adsorption
scale applications too expensive. A PSA process is based on the principle that the specific
• Urea electrolysis: Hydrogen can be made from urine adsorbents are capable of adsorbing different gas mol-
via urea electrolysis [10], which is 332 % more energy ecules with different affinity on the basis of partial pres-
efficient than using water. However, this technology is sure, size, and polarity. Two basic stages are involved:
still in the research stage. adsorption and regeneration or desorption. The operating
• Biohydrogen routes: Biomass and organic waste streams pressure in the adsorption stage is higher than in the
can be converted into biohydrogen, either with bio- desorption stage. Because the adsorbent capability for
mass gasification or steam reforming as discussed impurities is much higher than for hydrogen at certain
above, or with biological conversion processes such as partial pressures, most of the impurities are adsorbed
fermentative hydrogen production [11] and biocata- together with only a small amount of hydrogen. The impu-
lyzed electrolysis [12]. Although these routes are theo- rities can then be removed from the adsorbent by reducing
retically feasible, the challenge here is to make such the pressure.
technologies commercially viable. The process operates on a cyclic basis. Multiple
adsorbers are used to continuously purify a feedstock
12.3 Hydrogen Purification Processes and provide a constant product and a tail gas. A typical
Alternatives available to satisfy the hydrogen requirement sequence chart is shown in Figure 12.4 for a system with
in refineries are limited. Hydrogen can be generated by four adsorbers. A hydrogen stream is separated from the
steam reforming or partial oxidation, or it can be recovered feedstock in the adsorption phase. The adsorber then goes
from refinery off-gases. In some cases, the refiners can buy through co-current depressurization to repressure other
hydrogen from a third party. Among these options, recover- adsorbers and remove impurities from the adsorbent
ing hydrogen from refinery off-gases can be considerably while producing a tail gas. The purge from other adsorbers
cheaper in operating cost and capital investment. It is and finally the product hydrogen are used to repressure
worth prioritizing the recovery of hydrogen from refinery the adsorber until it is ready for the next adsorption.
off-gases with reasonable amounts. The product hydrogen is available at roughly the same
The off-gases containing hydrogen are from catalytic pressure as the feed. The pressure drop between feed and
reformers, hydroprocessors, fluid catalytic cracking (FCC) product is nominal at 10 psi. The product hydrogen is
units, and other refining or petrochemical units. The typical always in very high purity (up to ≥99.9 %) and the impuri-
content of some off-gases is listed in Table 12.4. ties will appear in product in the sequence of adsorption
The purification processes include PSA, membrane strength to adsorbent. The relative adsorptivity of typical
separation, cryogenic processes, and gas-liquid absorp- feed impurities is given in Table 12.5.
tion. Each of these processes is based on different The performance of a PSA unit can be evaluated
separation principles and therefore have specific pro- by the hydrogen recovery, which is defined as the ratio
cess characteristics. The selection of these purification of the amount of hydrogen contained in the product by
processes depends on the economic aspects as well as the amount of hydrogen contained in the feedstock. The
process flexibility, reliability, and ease of future expansion. hydrogen recovery is influenced by tail gas pressure, feed
Tremendous effort has been made to find the guidelines pressure, feed and product purity, unit configuration,
for the proper selection. Although most methods give the numbers of equalization phases, etc. Low tail gas pres-
physical insights, they are only instructive for the purifica- sure can significantly improve the hydrogen recovery
tion process design. (Figure 12.5). However, compressing tail gas may be
The appropriate purification system can decrease the necessary in order to match the fuel system pressure in
hydrogen plant capacity in a new design or provide cheaper a refinery or for other usage, which perils the economics
hydrogen in a retrofit project. of PSA units. Therefore, the selection of the appropri-
ate tail gas pressure is extremely important. The effect
of feed gas pressure on hydrogen recovery is less than
that of the tail gas pressure. Figure 12.6 shows there is
Table 12.4—Typical Content of Some Refinery
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an optimal feed pressure. Miller and Stoecker suggested

Off-Gases
that the minimum pressure ratio between the feed and
Hydrogen the tail gas is approximate 4:1, and the optimal range of
Off-Gas Sources Concentration (vol %) Pressure (psig)
feed pressure is 200–400 psig. A low feed purity is not
Catalytic reformer 70–90+ 250–400 recommended because of poor hydrogen recovery. The
Hydroprocessor low product hydrogen purity can increase the hydrogen
recovery, but the effect is relatively small (Figure 12.7).
High pressure 75–90 800–2500
Most PSA units are designed to achieve high hydrogen
Low pressure 50–75 100–250 purities.
FCC unit 15–20 100–250 The advantage of using PSA processes to separate
Delay coker (DCU) hydrogen from refinery off-gas is that the product purity
can be very high and the impurities can be controlled in
Toluene 55 400–500
part-per-million levels. However, the tail gas is difficult to
hydrodealkylation
(TDA) reuse because of its low pressure. A computer aid control
gives PSA a wide operation range, and its reliability has
Data from Miller and Stoecker [13].
been proven by long-term operations.

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Chapter 12 n Hydrogen Management 293

is the fast gas, which has higher permeability and enriches

the low-pressure side of the membrane. The pressure dif-
ference between the permeate and the residue provides the
driving force for the diffusion of gas across the membrane.
The membrane performance is much more dependent on
the feed to permeate the pressure ratio rather than the
operating pressure [13,14]. The strength of a membrane
limits the design of pressure difference. Because hydro-
gen is always recovered as a permeate, there is a tradeoff
between the hydrogen recovery and the product pressure
drop. Figure 12.9 illustrates that when the same recovery
is maintained, increasing the permeate pressure decreases
hydrogen purity and increases the membrane area—the
cost of compression is not taken into account.
Unlike PSA, a membrane process cannot remove
impurities to a very low level; thus, it is not suitable when
a process requires fine impurity removal. The hydrogen
purity in the permeate can be low. The hydrogen recovery
increases whereas the product purity drops, as shown in
Figure 12.10. A typical membrane design with condensate
protection is shown in Figure 12.11.
The performance of a membrane system can be
improved by a multistage design. Spillman [14] reviewed
] F F G ] the performance principles of gas membrane separation
and demonstrated some commercial applications of mem-
brane separation processes, including hydrogen recovery.
] FRXQWHUFXUUHQWU ]
Through the introduction of designs for single-stage and
multistage membranes, it is indicated that the membrane
F F G ]
designs are very much case dependent. The advantages
of membrane gas separation are low capital cost even at

FRXQWHUFXUUHQWG ]

U ]

Figure 12.4—PSA cycle sequence chart.

12.3.2 Membrane Separation

A membrane separation is achieved by different perme-
ations between hydrogen and impurities. Table 12.6 gives
relative permeabilities of some typical components. The
most popular membrane used in hydrogen recovery is
composite hollow-fiber membrane, which is composed by
an active layer and a support layer. Gases pass through a
membrane in two sequential steps: solution and diffusion. Figure 12.5—Effect of tail gas pressure on PSA recovery. Data
A simplified process is shown in Figure 12.8. The permeate from Miller and Stoecker [13].

Table 12.5—Relative Adsorptivity of Typical Components

Nonadsorbed Light Intermediate Heavy
H2 O2 CO C3H6
He N2 CH4 C4H10
Ar C2H6 C5+
CO2 H2S
C3H8 NH3
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

C2H4 BTX
H2O
Data from Miller and Stoecker [13].

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294 Petroleum Refining and Natural Gas Processing

Table 12.6—Relative Permeability of Typical

Components

6\VWHPUHODWLYHFRVW
High Medium Low
H2 C1 C2+
H2O O2 N2
H2S
CO2

+\GURJHQSXULW\Y
+\GURJHQ5HFRYHU\

Figure 12.9—Hydrogen vs. purity for membrane system. Data

from Spillman [14]

+\GURJHQUHFRYHU\
)HHG3UHVVXUHSVLJ
Figure 12.6—Effect of feed pressure levels on PSA system
recovery. Data from Miller and Stoecker [13].

+\GURJHQSXULW\

Figure 12.10—Hydrogen recovery vs. purity for membrane

system. Data from Miller and Stoecker [13].
+\GURJHQ5HFRYHU\

low gas volumes, ease of operation, low energy consump-

tion, and good space efficiency. Compared with other gas
separation processes, the many research efforts made for
new membrane technologies have brought membrane gas
separation into an increasingly important process for gas
separation and production.

12.3.3 Cryogenic Separation

Cryogenic separation is a low temperature process that
exploits the high relative volatility of hydrogen, compared
with other gas components, to separate hydrogen. Figure
3URGXFW+\GURJHQ3XULW\YRO
12.12 shows the flow diagram for a typical partial conden-
Figure 12.7—Effect of product purity on PSA system hydrogen sation process. The feed is cooled in exchanger X-1 to a
recovery. Data from Miller and Stoecker [13]. temperature at which most C2+ hydrocarbons condense.
The two-phase stream is then separated in separator S-1.
The hydrogen-CH4 vapor from S-1 is sent to exchanger X-2,
where it is cooled to a temperature low enough to provide
the required hydrogen product purity. The cooled stream
enters separator S-2 and the vapor from S-2 becomes the
hydrogen product after it is warmed in X-1 and X-2. The
hydrocarbon liquids from S-1 are throttled to a vaporiza-
tion pressure when exchanged against the incoming feed
stream in exchanger X-1. This stream can be withdrawn
separately at its highest pressure as a byproduct or mixed
with the CH4 reject stream at a lower pressure. The CH4-
Figure 12.8—Single-stage membrane process. rich liquid from S-2 is throttled to a pressure at which it
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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Chapter 12 n Hydrogen Management 295

Figure 12.11—Membrane process with filtration for condensate protection.

will boil and provide the necessary temperature difference hydrogen recovery cost can be largely reduced if the value
to the feed to S-2. The S-2 temperature sets the hydrogen of hydrocarbon byproducts is considered.
product purity by controlling the amount of CH4 remaining
in the vapor phase. The separators S-3 and S-4 are used to 12.3.4 Hybrid Systems
provide the proper distribution of liquid and vapor into the Because different hydrogen purification processes use
multiple passes of the heat exchangers. As shown in the dia- different separation principles, the characteristics of
gram, the refrigeration required by the process is obtained one process are distinctive from others. Efficient inte-
by Joule–Thomson expansion of the hydrocarbon. If the gration of those processes can combine the merits and
process itself cannot provide sufficient coolant, external achieve competitive purification results. The process
refrigeration is required. Therefore, high hydrogen purity characteristics that can be taken into account in the
in feed can dramatically increase operation cost. hybrid system design are
Thermodynamically, a cryogenic process has higher • PSA: Produces high purity product and completely
hydrogen recovery than other purification processes (92– removes low boiling point impurities.
97 %). The hydrogen purity in the product is controlled by • Membrane separation: High hydrogen recovery with
equilibrium and has less impact on recovery than that in high residue pressure.
membrane separation. High product purity leads to large • Cryogenic process: High hydrogen recovery with easy
investment. recovery of hydrocarbon byproducts.
The advantage of using cryogenic separation is that Ratan [15] proposed hybrid system designs by the
the process can deal with low feed purity and give high integration of membrane-PSA, cryogenic-membrane, and
hydrogen recovery. However, pretreatment is sometimes PSA-cryogenic processes and their possible applications
necessary to remove low boiling impurities such as N2 and (Figures 12.13–12.15). Pacalowska et al. [16] analyzed
CO before cryogenic separation as well as the components the economics and flexibility of a combination of PSA-
such as CO2, H2O, H2S, and C5+ to an appropriate level to cryogenic processes by case studies and concluded that this
avoid freezing. The application is only economically attrac- combination has a lower hydrogen production cost after
tive in large-scale units because of high capital cost. The accounting for the byproduct value when compared with a
PSA process alone and a hydrogen plant.

12.4 Hydrogen Transportation and

Distribution
For the refining industry, pipelines have been used to trans-
port and distribute hydrogen for more than 50 years, which
is also the case for gas utility companies (e.g., Air Liquide,
Air Products and Chemical, Inc., and Praxair) to supply
hydrogen gas to their customers. The operating pressure for
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

hydrogen transportation in pipelines is typically between 1

and 2 MPa, but pressure up to 10 MPa is also used in some
cases. Hydrogen pipelines need to be made of nonporous
materials such as stainless steel to avoid hydrogen leak-
age and brittle material. Therefore, the investment cost for
hydrogen pipelines of a given diameter is approximately
twice that of natural gas pipelines [17]. The energy required
to move hydrogen through a pipeline is on average approxi-
mately 4.6 times higher per unit of energy than for natural
Figure 12.12—Partial condensation cryogenic process. Data gas. Therefore, compared with natural gas, hydrogen dis-
from Miller and Stoecker [13]. tribution facilities are more expensive to build and operate.
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296 Petroleum Refining and Natural Gas Processing

Figure 12.13—A hybrid system: Membrane and PSA system.

Figure 12.14—A hybrid system: Membrane and cryogenic separation.

In theory, hydrogen could also be transported and 12.5 Network Targeting—The Hydrogen
distributed in liquid form. However, the liquefaction of Pinch Concept
h ydrogen is hugely expensive because approximately A refinery hydrogen network contains three main ele-
42 % of the energy content of the liquid hydrogen ments: (1) hydrogen producers such as steam and cata-
would be needed to liquefy hydrogen at –253°C [18]. lytic reformers, (2) hydrogen consumers such as various
Therefore, oil refineries do not commercially practice hydrotreators and hydrocrackers, and (3) hydrogen puri-
liquefaction of hydrogen in their internal hydrogen fication units such as PSA and membrane and cryogenic
distribution. separation. They are then linked together through neces-
Because of its extremely low boiling point and low sary piping and compression. An example of a refinery
molecular weight, storage of hydrogen in whatever form hydrogen network is shown in Figure 12.16. To systemati-
(gaseous, liquid, or solid) is expensive. Therefore, refin- cally analyze such a network, Alves [20] proposed a pinch
ery hydrogen systems are designed on the basis of supply approach for targeting the minimum hydrogen utility.
on demand. However, for gas utility companies and the This work is based on pinch technology and exploits
future hydrogen economy, hydrogen storage is an impor- an analogy with heat exchanger network synthesis. The
tant subject. Various technologies for hydrogen storage method identifies sources and sinks of hydrogen, which
are available, such as large-scale underground gas stor- are analogous to hot and cold streams in heat exchanger
age, on-board gaseous composite tanks or glass micro- networks.
spheres, on-board liquid storage (pure or with solutions),
and on-board solid storage with carbon and other high 12.5.1 Sink and Source Location
surface area materials or various hydrides, etc. Interested A typical hydrogen consumer including a hydrotreating
readers can refer to reference 19 for more information on reactor and a separator can be simplified as shown in Fig-
this subject. ure 12.17. Hydrogen is used to react with liquid hydrocar-
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Chapter 12 n Hydrogen Management 297

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 12.15—A hybrid system: Cryogenic and PSA processes.

bons. The partial pressure in the reactor is a very important

parameter in the reaction. In this part of the work, the
partial pressure of hydrogen is assumed to be constant, as
well as other parameters such as operating temperature,
reactor feedstock, products, etc. Under these assumptions,
constant flow rate and hydrogen purity is imposed on the
reactor gas inlet stream. Therefore, if the operating condi-
tion does not change, the inlet of the reactor and the outlet
of the separator will be fixed. Thus, the mixture of the
make-up hydrogen and the recycle is defined as the sink,
and the mixture of the purge and the recycle is defined as
the source (Figure 12.17).

12.5.2 Hydrogen Composite Curve and

Hydrogen Surplus Curve
The mass balance of each sink and source in a hydrogen Figure 12.16—A refinery hydrogen network flow diagram.
distribution network can be conveniently represented in
a two-dimensional plot with the flow rate of total gas on
the horizontal axis and the purity on the vertical axis. One of the necessary conditions for a feasible network
Plotting the hydrogen demand profile and the hydro- is that there is no negative hydrogen surplus anywhere
gen supply profile gives the hydrogen composite curves in the hydrogen surplus diagram, because if this is the
(Figure 12.18). This purity profile contains the hydrogen case, the sources cannot provide enough hydrogen to the
sinks and sources ordered by decreasing purity. Sepa- sinks. For an existing network, parts of the surplus curve
rately the sink and the source curves start at zero flow are always positive. The hydrogen utility can be reduced
rate and continue until the lowest purity is represented. through moving the curve toward the vertical axis until
Where the hydrogen supply curve is above the hydro- a vertical segment between the purity of the sink and the
gen demand curve, the area between the two profiles is source touches the zero axes (Figure 12.20). The purity at
marked as surplus (+), which means the sources provide which this occurs is defined as the “hydrogen pinch” and
more hydrogen than required by the sinks. If the hydro- is the theoretical bottleneck on how much hydrogen can
gen supply is below the hydrogen demand curve, the area be used from the sources to the sinks. The hydrogen utility
between the two profiles is marked as deficit (–), which flow rate that results in a pinch is the minimum target and
means sources do not provide enough hydrogen to the is determined before any network design [21].
sinks [21].
The hydrogen composite curves can be divided into 12.5.3 Purity Tradeoff and Purification Analysis
different regions with alternating surplus and deficit of Hydrogen pinch analysis is useful not only to determine
hydrogen. Calculating these surpluses and deficits (area) the target of minimum hydrogen consumption but also
of hydrogen and plotting them against the purity level to carry out the analysis of purity tradeoff and placement
constructs the hydrogen surplus diagram, as illustrated in of purification units [21]. One of the aspects is to reduce
Figure 12.19 [21]. hydrogen utility flow rate by increasing the purity of one
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298 Petroleum Refining and Natural Gas Processing

Figure 12.17—Simplified diagram of a hydrogen consumer showing source and sink locations.

Figure 12.18—Hydrogen composite curve.

or more sources. It takes advantage of the fact that if two tion scenarios. It is found that purification across the pinch
streams have the same flow rate of hydrogen, the one can reduce the requirement of the utility; at the same time,
with higher purity will provide the hydrogen system with because the hydrogen loss happens below the pinch, the
more hydrogen surplus. The resulting effect on the hydro- utility flow rate will not be affected. The consequences of
gen surplus curve is shown in Figure 12.21. The initially different placements are shown in Figure 12.22 [21].
pinched system (dotted line) becomes unconstrained (solid
line) with an increase in the utility purity. The additional 12.5.4 Summary of Hydrogen Pinch Analysis
hydrogen surplus thus created can be used to reduce the Hydrogen pinch is a graphical approach to find the mini-
hydrogen utility, resulting in a lower target. This gives mum hydrogen utility in distribution networks. It can
an option for debottlenecking the hydrogen distribution provide insights to hydrogen distribution and is easy to
system. develop. It is particularly useful to identify the scope of a
The purification of hydrogen sources can also be ana- potential improvement in an existing hydrogen network
lyzed. The installation of a hydrogen purification unit adds before spending a significant amount of time and capital
one more sink and two sources to the hydrogen distribu- for detailed engineering design. However, it also has some
tion system. The sink is the feedstock to purification. The drawbacks.
sources are the purified product stream and the residue One of the major limitations with the method is that
stream. The introduction of a new purification unit usually the targets are set based only on the flow rate and purity
affects the entire hydrogen system even if the unit is captive requirements. The targeting method assumes that any
to an individual consumer process. The savings generated streams containing hydrogen can be sent to any consumer,
by the purification unit are assessed in the steps of placing regardless of the stream pressure. In reality, a source can
the purification unit inside of the network, applying the only feed a sink if it is in a sufficient pressure level. Sig-
pinch method to find a new target. The multiple purifica- nificant investment in compression equipment might be
tion options can be evaluated one by one. required to achieve the target. Thus, the targets generated
There are three possible placements for a purification may be too optimistic in a real design.
unit in the hydrogen surplus curve: (1) above the pinch, In addition, the analysis of the placement of purifica-
(2) across the pinch, or (3) below the pinch. The general tion units is processed on the basis of arbitrary selection
conclusions are then made to quantify different purifica- through hydrogen pinch analysis and can give a theoretical
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Chapter 12 n Hydrogen Management 299

Figure 12.19—Hydrogen surplus diagram.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 12.20—Targeting the minimum utility by varying the hydrogen utility flow rate until a pinch is formed.

target before design. However, because the purification is 4. Accuracy and feasibility of hydrogen network design.
also an important design option subject to practical con- Methods have been developed to address all four issues
straints, this target is not sufficient to be the guide for the above, mainly based on advanced mathematical program-
overall optimal design or debottlenecking. Therefore, a ming algorithms.
more comprehensive and detailed approach is necessary for
the hydrogen distribution network design, which can also 12.5.6 Hydrogen Network Optimization with
deal with the objective function of the minimum total cost Pressure Consideration
of the network instead of the minimum hydrogen utility. Hallale and Liu [22] developed an automated design
approach for hydrogen network management to account
12.5.5 Detailed Hydrogen Network for practical constraints. The method is based on the opti-
Optimization and Design mization of a reducible superstructure (Figure 12.23). In
There are four major issues for advanced hydrogen network this approach, the pressure constraints are included in the
management: design. Multiple constraints can be incorporated to achieve
1. Systematically taking into account practical con- optimal realistic designs. To find the realistic design solu-
straints, such as pressure matching, compression, pip- tion, the objective function is to minimize the total cost
ing, capital and operating cost, etc. instead of only minimizing the hydrogen utility. Capital and
2. Trading off various purification options. operating costs are taken into account by modelling exist-
3. Properly integrating a hydrogen plant with a hydrogen ing and new compressors, purifiers, and piping changes.
network. Hydrogen cost is weighed by the price of hydrogen utility
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300 Petroleum Refining and Natural Gas Processing

Figure 12.21—Effect of utility purity increment on a hydrogen surplus curve.

Figure 12.22—Evaluate purification scenario using a hydrogen surplus curve.

in the design. Retrofit options (e.g., additional purification, as a feed. Therefore, such interactions need to be properly
compression, and piping changes) are decided automati- exploited. Liu [24] developed a method to integrate hydro-
cally through optimization. gen generation into hydrogen networks. The hydrogen
plant is modelled by correlating process data from com-

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
12.5.7 Purifier Selection and Integration prehensive process simulation. The hydrogen plant model
Strategy covers a wide feed range from natural gas and refinery off-
Liu and Zhang [23] further extended the automated design gas hydrocarbons to light naphtha. A superstructure (Fig-
approach to integrate hydrogen purification processes ure 12.24) is then developed to account for the integration
in hydrogen networks. A methodology was proposed to of hydrogen plants and purifier operations. The refinery
select the appropriate purifiers from PSA processes and off-gases are evaluated as the possible feed to hydrogen
membrane or hybrid systems for recovering hydrogen plants and purification units. The tail gas streams from
from refinery off-gases. Through the understanding of the purification units are considered as candidate feedstock to
tradeoffs among hydrogen savings, compression costs, and hydrogen plants or being sent to a fuel system after neces-
capital investment, a superstructure similar to the one sary compression.
in Figure 12.23 was built to include possible purification
scenarios. The shortcut models for different purification 12.6.1 Detailed Simulation to Ensure Accuracy
units were developed. The recovery rate of purifiers was and Feasibility
also modelled to optimize process parameters. This method For the above hydrogen pinch analysis and mathematical
achieved the optimal design for overall hydrogen networks programming methods, there is one major assumption:
at a conceptual level. Refinery gases are treated as a binary mixture of hydrogen
and CH4 by combining all of the impurities of hydrogen-
12.6 Integration of Hydrogen Plant containing gas streams as CH4. This assumption can lead to
A hydrogen plant not only supplies hydrogen to hydrogen infeasibility in the network after optimization because the
consumers through a hydrogen network, but it also can hydrogen management technology is not able to capture the
take off-gas from hydroprocessors and purification units change in some importance performance parameters (e.g.,
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Chapter 12 n Hydrogen Management 301

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 12.23—An example of reducible superstructure.

Figure 12.24—Superstructure—covering possible operating schemes.

hydrogen partial pressure, hydrogen-to-oil ratio, sulfur con- late vapor-liquid equilibrium is required, together with the
tent, etc.) of hydrogen consumers because of changes in the composition information of the vapor and liquid streams.
impurity compositions of make-up streams. To obtain accu- Therefore, a new and more detailed consumer model can
rate solutions, there is a need for having a multicomponent be built as shown in Figure 12.25. The simulation of indi-
methodology to represent hydrogen streams in hydrogen vidual units is still based on the assumption that there is
network management instead of lumping all impurities as no change in reaction by minimizing the change of the
CH4 and treating hydrogen streams as a binary mixture of hydrogen-to-oil ratio and hydrogen partial pressure caused
hydrogen and CH4. by the change in impurity composition. A whole hydrogen
To take into account impurities, an integrated approach network can then be set up in a simulator for feasibility
was developed by Zhang et al. [25]. A flash routine to calcu- check using the extended hydrogen consumer model.
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302 Petroleum Refining and Natural Gas Processing

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 12.25—Extended hydrogen consumer model for impurity consideration.

all refiners. Each refinery has its particular process avail-

ability and constraints and maintains its own operating
scheme. In today’s business climate, the favorite solution
is to increase saving and maximize effectiveness of invest-
ment. However, the intelligent applications developed from
the approach discussed here can aid refiners in finding
their optimal tailored solutions.

References
[1] Haun, E.C., Anderson, R.F., Kauff, D.A., Miller, G.Q., and
Stoecker, J., “The Efficient Refinery Hydrogen Management in
the 1990’s,” presented at the Spring 1990 Technology Confer-
ences, Des Plaines, IL, 1990.
[2] Aitani, A.M., and Ali, S.A., “Hydrogen Management in Modern
Refineries,” Erdöl und Kohle, Vol. 48, 1995, pp. 19–24.
[3] Rana, M.S., Sámano, V., Ancheyta, J., and Diaz, J.A.I., “A Review
of Recent Advances on Process Technologies for Upgrading of
Heavy Oils and Residua,” Fuel, Vol. 86, 2007, pp. 1216–1231.
Figure 12.26—Overall methodology for refinery hydrogen [4] McGrath, M.J., and Houde, E.J., “Upgrading Options for Pro-
management. cessing Heavy Crudes,” presented at the American Institute of
Chemical Engineers Spring 1999 Meeting, March 14–18, 1999.
12.6.2 The Overall Methodology for Refinery [5] Lamber, G.J., Schoeber, W.J.A.H., and van Helden, H.J.A.,
“The Hydrogen Balance in Refineries,” presented at the Fos-
Hydrogen Management ter Wheeler Heavy Oil Processing and Hydrogen Conference,
The advanced hydrogen management [25] follows the Noordwijk, The Netherlands, April 1994.
principles of the overall framework shown in Figure 12.26. [6] Phillips, G., “Hydrogen—Innovative Business Solutions for
Although the detailed simulation can also be supported 2005 and Beyond,” presented at the European Refining Tech-
with commercial simulation packages, the hydrogen pinch nology Conference—Process, Paris, France, November 1999.
[7] Gardner, A., “Refining Details—Hydrogen Production What’s
analysis is based on the graphical approach, and the auto- Available,” Today’s Refinery, February/March, 1998, pp. 27–31.
mated design is performed using advanced mathematical [8] Hiller, M.H., Lascatena, J.J., and Miller, G., “Hydrogen for
programming methods (nonlinear programming and mixed Hydroprocessing Operation,” presented at the 1987 National
integer linear programming). Petrochemical and Refiners Association Annual Meeting, San
Antonio, TX, March 1987.
12.7 Conclusions [9] Vervalin, C.H., Ed., “Gas Processing Handbook,” Hydrocarbon
Process., Vol. 73, 1994, pp. 82–106.
Hydrogen supply has become one of the focal points in [10] Boggs, B.K., King, R.L., and Botte, G.G., “Urea Electrolysis:
many refinery operations because of recent developments Direct Hydrogen Production from Urine,” Chem. Commun.,
in environmental and fuel legislation. Therefore, it is impor- Vol. 32, 2009, pp. 4859–4861.
tant to raise the awareness of advanced techniques for [11] Tao, Y., Chen, Y., Wu, Y., and Zhihua, Z., “High Hydrogen Yield
hydrogen network management. The technology developed from a Two Step Process of Dark- and Photo-Fermentation of
Sucrose,” Int. J. Hydrogen Energy, Vol. 32, 2007, pp. 200–206.
for refinery hydrogen management has been successfully
[12] Strik, D.P.B.T.B., Hamelers, H.V.M., Snel, J.F.H., and Buisman,
applied in the refining industry. It not only helps in reduc- C.J.N., “Green Electricity Production with Living Plants and Bac-
ing hydrogen consumption, but it also keeps capital costs teria in a Fuel Cell,” Int. J. Energy Res., Vol. 32, 2008, pp. 870–876.
low in debottlenecking projects by identifying the most [13] Miller, G., and Stoecker, J., “Selection of a Hydrogen Separa-
cost-effective revamping options through simple hydrogen tion Process,” presented at the 1989 National Petrochemical
pinch analysis for targeting and comprehensive mathemati- and Refiners Association Annual Meeting, San Francisco, CA,
March 1989.
cal programming methods for detailed solutions. [14] Spillman, R.W., “Economics of Gas Separation Membranes,”
Although these approaches have been proven success- Chem. Eng. Prog., Vol. 85, 1989, pp. 41–62.
ful by many industrial projects, it needs to be pointed out [15] Ratan, S., “Hydrogen Management System,” KTI Newsletter,
that there is no general answer for hydrogen problems for Fall, 1994, pp. 24–32.
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Chapter 12 n Hydrogen Management 303

[16] Pacalowska, B., Whysall, M., and Narasimhan, M.V., “Improve [21] Alves, J., and Towler, G.P., “Analysis of Refinery Hydrogen
Hydrogen Recovery from Refinery Off-Gases,” Hydrocarbon Distribution Systems,” Ind. Eng. Chem. Res., Vol. 41, 2002,
Process., Vol. 75, 1996, pp. 55–59. pp. 5759–5769.
[17] Mintz, M., Folga, S., Molburg, J., and Gillette, J., “Cost of Some [22] Hallale, N., and Liu, F., “Refinery Hydrogen Management for
Hydrogen Fuel Infrastructure Options,” Argonne National Lab- Clean Fuels Production,” Adv. Environ. Res., Vol. 6, 2001, pp.
oratory, Transportation Technology R&D Center, January 2002. 81–98.
[18] Gielen, D., and Simbolotti, G., “Prospects for Hydrogen and [23] Liu, F., and Zhang, N., “Strategy of Purifier Selection and
Fuel Cells,” presented to the Transportation Research Board, Integration in Hydrogen Networks,” Chem. Eng. Res. Des., Vol.
Washington, DC, January 2006. 82, 2004, pp. 1–16.
[19] Riis, T., Sandrock, G., Ulleberg, Ø., and Vie, P.J.S., “Hydrogen [24] Liu, F., “Hydrogen Integration in Oil Refineries,” Ph.D. thesis,
Storage—Gaps and Priorities,” IEA Hydrogen Implementing Department of Process Integration, University of Manchester
Agreement, Paris, 2005. Institute of Science and Technology, 2002.
[20] Alves, J., “Analysis and Design of Refinery Hydrogen Distribution [25] Zhang, N., Singh, B.B. and Liu, F., “A Systematic Approach
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13
Design Aspects of Separation Units and
Processing Equipment
M.C. Rodwell1 and M.R. Riazi2

Nomenclature P Pressure or partial pressure

Symbols Pr Prandtl number
A Absorption factor defined in Eq 13.42, dimensionless R Reflux ratio (= L/D for distillation column), dimen-
A Surface area for heat transfer sionless
Ac Column cross sectional area, m2 R Hot fluid to cold fluid temperature change ratio,
AX Cross sectional area Eq 13.55
B Rate of bottom product, mol/h r Radius
Cp Specific heat capacity at constant pressure r Pressure ratio
Cv Specific heat capacity at constant volume RD Fouling resistance for heat transfer
D Rate of distillate product, mol/h Ro Universal gas constant (8.3144 kJ/kmol·K, 1.9859
D Diameter of a separator Btu/lbmole·°R)
dc Column diameter Ra Rayleigh number
dp Packing particle diameter Re Reynolds number
EM Murphree efficiency in a distillation column q Heating rate for reboiler or condenser in a distilla-
defined in Eq 13.26, dimensionless tion column
Eo Overall column efficiency defined in Eq 13.15, Q Heat transfer rate (MW, Btu/h)
dimensionless Q Volumetric flow (m³/h, usgpm, acfm)
Ei Recovery factor for component i in a gas absorp- S Stripping factor, dimensionless
tion column defined in Eq 13.43, dimensionless SG Specific gravity
F Amount of feed, moles (rate in mol/h) T Temperature
F LMTD correction factor TH Time, hold-up volume
FT Probability density function (PDF) for boiling TS Time, surge volume
point T (in Eqs 13.5 through 13.7) t Temperature, air
g Gravitational acceleration (9.80655 m/s²) u Velocity
GOR Gas-to-oil ratio (scf/bbl) U Overall heat transfer coefficient
H Enthalpy (J/kg) V Amount of vapor (or gas), moles (rate in mol/h)
h Column height used in Eqs 13.30 and 13.36 V Volume
h Local heat transfer coefficient (W/m²·K) used in TF Feed temperature, K
Eqs 13.70 and 13.72 ΔTLMTD Log mean temperature difference, defined in Eq
h Head of fluid used in Eqs 13.135 and 13.136 13.51
K Souders-Brown factor, used in Eq 13.95 W Power (work)
K i Equilibrium ratio in vapor-liquid equilibria (Ki = x Mole fraction of light component in liquid phase,
yi /xi), dimensionless dimensionless
k Thermal conductivity y Mole fraction of light component in vapor phase,
L Amount of liquid or reflux (for distillation col- dimensionless
umn), moles (or rate in mol/h) Z Compressibility factor
L Length of a separator vessel, tangent to tangent
m Mass fraction of a component Greek Letters
ML Molecular weight of liquid mixture αAB Relative volatility of component A to B, dimen-
MW Molecular weight sionless
N Number of actual or theoretical plates or equilib- αAB Relative volatility of light key to heavy key in
rium stages in a column multicomponent distillation
N Number of moles Δ Difference between two values of a parameter
N Speed, rpm θ A dimensionless parameter defined in Eq 13.21
NSS Suction-specific speed Θ Time, settling or rising
n Polytropic exponent γ Ratio of specific heats, Cp/Cv
Nu Nusselt number, dimensionless ε Void fraction, used in Eq 13.111
1
Fluor Canada, Ltd., Calgary, Alberta, Canada
2
Kuwait University, Kuwait
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305
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306 Petroleum Refining and Natural Gas Processing

η Efficiency HETP Height equivalent to a theoretical plate

ψ A dimensionless parameter defined in Eq 13.22 HLL High liquid level
μ Dynamic viscosity HILL High interface liquid level
ν Kinematic viscosity HVGO Heavy vacuum gas oil
π Ratio of the circumference of a circle to its diameter LHV Lower (net) heating value
ρ Density LHSV Liquid hourly space velocity
LLL Low liquid level
Superscript MOP Maximum operating pressure
L Value of a quantity for a liquid phase NLL Normal liquid level
NPSH Net positive suction head
Subscripts SG Specific gravity
A, B Value of a quantity for component A in a binary SI System International of Units
mixture of A and B (A being the light component) TEMA Tubular Exchanger Manufacturers Association
a Air
avg Average value of a quantity 13.1 Introduction
B Value of a quantity for the bottom product of a Petroleum refining and natural gas processing are complex
distillation column industries composed of hundreds of various equipments
boot Boot of a horizontal separator and units. The major units involved in these industries may
bp Bubble point for a mixture (equivalent to boiling be categorized as separation, conversion, finishing, and sup-
point) port units. This chapter focuses on the design aspects of
C Condenser for a distillation column separation units, including desalting, distillation, absorption,
C Continuous phase extraction, and heat-transfer equipment such as fired heat-
CMTD Corrected mean temperature difference ers, heat exchangers or coolers, and pumps and compres-
D Value of a quantity for the distillate (overhead) sors. In addition, design aspects of two- and three-phase
product of a distillation column separation units are also discussed in this chapter. Some

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DP Dewpoint design and operational aspects of conversion processes,
E Enriching section of a distillation column natural gas processing, and control units are presented in
eff Effective chapters that cover these topics (see Chapters 5–12, 14–22,
F Value of a quantity for the feed and 25–31). However, the units discussed in this chapter are
f Fluid (in Eq 13.70) used in various plants throughout refinery and natural gas
f Frictional (in Eq 13.128) processing industries.
G Greater, as in Eq 13.52
HK Heavy key component in multicomponent distil- 13.2 Crude Oil Desalting Units
lation Crude oil delivered to a refinery often contains small
LK Light key component in multicomponent distillation amounts of produced water, usually less than 1 vol %.
LMTD Log mean temperature difference Produced, or connate, water usually contains some quantity
L or l Liquid phase of dissolved ionic salts. Chlorides of sodium, magnesium,
i Inside of tube and calcium are the most common salts present in crude
i Value of a quantity for component “i” in a mixture oils; other salts may be present depending on the geology of
min Minimum the reservoir from which the petroleum was sourced.
max Maximum Removal of the salts from the crude oil is important
mix Mixture because these salts can cause corrosion and fouling of units
m Atomizing medium throughout the refinery. Hydrolysis of MgCl2 and CaCl2 in
O Outside of tube the presence of steam in the crude and vacuum distillation
o Initial value before a process begins units will produce hydrogen chloride gas, which is a strong
min Minimum acid in the aqueous phase. Such strong acid condensation
P Particle in dispersed phase in the overhead systems of distillation columns can result
R Reboiler for a distillation column in very severe corrosion. Sodium chloride tends not to
r Radiant section hydrolyze and ends up in the bottoms products of the distil-
s Superficial or per stage or stack lation process. High levels of sodium and calcium salts in
sat Saturation condition the heavy products can promote fouling of furnace tubes in
src Source vacuum units, visbreakers, and delayed coking units. For
T Terminal these reasons, removal of these species from the feed oil is
th Theoretical value desired.
V Vapor phase The inlet crude oil is mixed with clean wash water, which
vap Vapor, as in vapor pressure is usually steam condensate or the overhead water from
w Wall condition the atmospheric and vacuum distillation units or perhaps
20 Values of property at 20°C phenolic sour water sourced from cokers or fluid catalytic
cracking (FCC) units. The oil and water are mixed thor-
Acronyms oughly via a static mixer and a special mix valve, which
API American Petroleum Institute is usually specified by the desalter supplier. The mix valve
ASTM American Society for Testing and Materials usually will have a pressure drop of 70–200 kPa to ensure
GPSA Gas Processors and Suppliers Association sufficient shear to mix the clean water with the connate water,
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 307

diluting the salt in the water phase. The selection and tuning Salt content in crude oils is usually quoted in units or
of this pressure drop is very important to the performance pounds per thousand barrels (ptb) or parts per million by
of the desalter. Too little shear will result in ineffective salt weight (ppmw). The conversion between the two can be
removal whereas too much will result in overly stable emul- calculated via
sions and rag formation.
The mixture is injected into the center of the vessel 2.853 ⋅ ptb
ppmw = (13.1)
between two horizontal electrically charged grids. The elec- SGoil
trical potential between the grids is usually in excess of
1000 V and is highly dependent on the electrical conductivity for crude oils with small water contents. For larger water
of the crude oil. The electric potential is an alternating cuts, such as in production facilities, this needs to be adjusted
current, and modern designs often use high frequencies to account for the volume and density of the connate water.
(i.e., many multiples of the normal 50/60-Hz power supply). Predicting the performance of a one- or two-stage
The purpose of the alternating electric potential is to vibrate desalter can be modeled using a simple mass balance that
the water droplets in the oil, causing them to contact each depends on an empirical factor called the contact efficiency.
other and coalesce into droplets large enough to settle out The contact efficiency can be determined from pilot studies
of the hydrocarbon phase by gravity. or evaluation of an operating unit. The authors’ experience
A schematic of an electrostatic desalter is shown in shows that contact efficiencies range from approximately
Figure 13.1, and a simplified flow diagram of a two-stage 80 % for light crudes (>40° API) to as low as 25 % for very
electrostatic desalter is shown in Figure 13.2. heavy, viscous crudes (<20° API). Because of this, wash

Figure 13.1—Electrostatic desalter schematic.

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Figure 13.2—Desalting process flow diagram.

AST-MNL58-11-0801-013.indd 307 3/12/13 2:24 PM

308 Petroleum Refining and Natural Gas Processing

Figure 13.3—Two-stage desalter material balance.

water rates for light crudes can be as low as 3–5 % while including the salt content, water content, and oil properties.
achieving reasonable salt removal whereas heavy crudes A general rule of thumb is that reduction of the salt content
may need up to 12 % wash water volume. to a level of 10 ptb (pounds per thousand barrels) can usually
For a two-stage desalter, the performance can be esti- be achieved in a single stage. Reducing the level to a value
mated using the following equations. The equations are closer to 1 ptb will require a second stage [2].
based on the mass balance diagram in Figure 13.3.
In the above figure, T is the volumetric flow of clean 13.2.1 Fluid Properties
oil, Wx signifies the volumetric flow of water per 1000 bbl The density and viscosity of the inlet crude oil blend are the
of crude, xx is the water content (vol %) of the oil, and Sx is primary considerations of a desalter because these govern
the salt content per volume of water (lb/bbl). The term WxSx the separation of the oil and water phases in the vessel
therefore indicates the salt content of the oil in pounds per itself. To improve the difference between the oil and water
thousand barrels. phases, it is desirable to operate the desalter at as high of
The water content of each stream in volume percent is a temperature as possible. However, there are constraints
related to the volumetric flow per thousand barrels by that must be considered.
• The operating pressure must be greater than the vapor
1000 ⋅ xx pressure of the crude oil feed at the desalter tempera-
Wx = (13.2)
(1 − xx ) ture because the desalter cannot operate with a vapor
phase. Some suppliers do offer units that can handle
First, we calculate the water recycle rate based on the small levels of vapor generation, but this is not recom-
expected dehydration performance of each stage: mended for most services.
• The seals around the electrical connections into the
WR = WB + WD − WC (13.3) vessel are generally limited to a maximum operating
temperature not greater than 149°C (300°F).
Next, we calculate the water rates after the mixers: • Some high-fidelity-level instruments are limited to
operating temperatures not greater than 130°C (266°F).
WM = W0 + E1WR It may be possible to mitigate this issue with cooling
(13.4)
WN = W2 + E2WD jackets to isolate the detector from the high-temperature
process fluid.
Next, we calculate the salt content of the recycle stream: Some very heavy crude oils (>940 kg/m³; <19° API) may
need to be diluted with a light cutter stock such as naphtha
W1W0 S0 (WN − W2 ) + WM WD SD (WN − E2W2 ) or kerosene to improve the density and viscosity to improve
WR SR = (13.5)
WM WN + W1E1 (W2 − WN ) the oil/water separation. Because the hydrocarbon phase is
the more viscous, the separation of water droplets from the
The salt content out of the first stage is determined via oil will govern the size of the desalter vessel. The selection
of the cutter stock should be made carefully to ensure that
W0 S0 + E1WR SR no asphaltenes are precipitated.
S1 = (13.6)
WM To determine if a crude blend will be challenging
to separate, a drag calculation can be performed. This
Finally, the salt content from the second stage can be found: requires iteration of the vessel sizing and drag calculations
(q.v., Section 13.7) to determine what size particles can be
W1S1 + WD SD − WR SR separated with respect to relative superficial velocities of
S2 = (13.7)
W2 the hydrocarbon and aqueous phases. If the water droplet
size required to overcome the drag forces is larger than
The derivation of these equations can be found in reference 500 μm, then separation will be challenging without very
[1], as can further discussion of desalter mass balances and long residence times. There are usually two reasons this
operation. One can rearrange the equations to solve for could be occurring. If the density of the oil and water are
wash water rates (WD), or one can use this method and iter- too similar, then there is not sufficient driving force for
ate until the desired result is achieved. the separation. The other possibility is that the viscosity
The question of whether a single-stage or two-stage of the oil phase is too high, which restricts the movement of
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desalter
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 309

temperature, dilution with cutter stock, or a different crude removing the entrained solids. This water stream should
blend to improve the separation. be quenched or cooled before routing to a tank or pond or
centrifuged for solids removal.
13.2.2 Emulsion Stability
Emulsion stability is usually affected by the presence of small 13.2.5 Rag Formation
solid particles in the oil or the presence of polar species in In many desalters, a layer of stable oil/water emulsion will
the petroleum, both of which will accumulate at the oil/water accumulate over time between the oil and water phases. This
interface of droplets. These can prevent the water or oil drop- rag layer can result intermittently from loss of chemical
lets from coalescing, thus inhibiting the separation process. additives or changes in crude charge, or it can be due to
Solid particles commonly found in crude oils can be continuous buildup as a result of fundamental properties

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asphaltenes, which may precipitate because of incompat- of the crude oil. The rag layer is either a water continuous
ibilities between crudes in the blend, and mineral solids layer containing oil droplets or vice versa. Additionally, the
such as fine clays. Crudes should be rigorously tested for droplets contained in the primary continuous phase may in
compatibility to prevent asphaltene precipitation in turn contain an emulsion of the other phase. This makes
the preheat train, which can foul exchangers and inhibit the rag layer particularly difficult to treat chemically.
desalter performance. Because of the high water content of the rag layer, it
Polar molecules can be any heteroatom containing has a very high electrical conductivity—essentially that of
molecules present in the oil, with oxygenates being the most the desalter brine. If the rag layer builds up such that it
surface active. Crudes with high naphthenic acid contents contacts the electrical grids, it will short-circuit the system,
or containing lighter aliphatic acids may act as surfactants. resulting in a trip. Therefore, it is necessary to withdraw the
Crudes with high calcium naphthenate content (e.g., Doba) rag layer from the desalter for treatment.
are known to be particularly difficult to desalt because of The rag layer draw is done simply through the use of
emulsion stability issues in the desalter and brine treatment nozzles between the grids. The rag should be drawn slowly,
processes. limiting the change at an interface level to less than 5 cm/
Chemicals are often added to the desalter fluids to assist min to prevent shorting of the grids. The rag can then be
in emulsion breaking and optimizing shear in the mixing quenched or cooled before routing to a tank for treatment.
valve, which is critical in reducing emulsion formation. Determination of the rag layer thickness in the
Recent investigations in some high naphthenic acid heavy desalter is a challenging issue. It usually cannot be seen
oils indicate that reduction in pH of the washing water can in a visual level gage glass, and the minimal density dif-
promote oil/water separation [2]. ference between the rag and water phase makes interface
floats unreliable. This was traditionally performed by
13.2.3 Hydrocarbon Conductivity taking samples from various elevations of the vessel to
Some crude oil blends may have high conductivities, determine the location of the interfaces. Modern capaci-
particularly those with high oxygen contents in the form of tance probes can provide some guidance, but again the
naphthenic and aliphatic acids. In some cases, two crudes difference between the rag layer and brine can be difficult
that individually have low conductivity may have increased to see. Additionally, heavy, high-viscosity crudes can coat
conductivity when they are blended; some have theorized the probes, limiting their usefulness. Newer gamma-ray
that this is due to the lighter crude improving the “mobility” devices can provide very detailed information about rag
of polar species in the heavier crude, although this has not distribution in the vessel.
been substantiated in the literature.
High conductivity results in electrical current flowing 13.2.6 Rag Processing
through the hydrocarbon phase between the electrodes The rag layer drawn from a desalter can be difficult to process
in the desalter. To maintain a high potential between the to recover clean oil and clean water. Chemical treatment and
grids, a large current can flow, resulting in very high power settling time in tanks can be effective in some circumstances.
requirements compared with a desalter operating in a low- Flotation cells have shown some effectiveness for rag treat-
conductivity crude. High conductivity can also result in ment, although for very heavy crudes this is unlikely to be
“arcing” or “shorting” of the grids, resulting in a trip of the effective because of the limited density difference of oil and
electrical supply, essentially shutting down the desalter. water. Centrifuges can be very effective for separation of the
rag layer, although high mineral content could result in high
13.2.4 Solids Content and Mud Wash maintenance costs. Pilot testing of rag separation technolo-
If the crude charge to the refinery is expected to have a high gies is recommended.
BS&W, particularly with an identified risk for high solids
content, the desalter should be provided with mud wash 13.3 Design of Distillation Columns
connections and a mud wash pump. The desalter circulation The distillation column was introduced in Section 5.5 of
pumps can be diverted for this purpose, but the ideal con- Chapter 5. In this section, we present design calculations
figuration has a dedicated mud wash pump. for tray and packed columns for binary and multicompo-
The mud wash pump takes water from the last-stage nent systems. Because distillation is based on the relative
desalter vessel or a clean water source and pumps it into the volatility of compounds and principles of vapor-liquid equi-
bottom of the vessel through a series of directional nozzles. librium (VLE) in the mixture, we begin this section with the
This should be done in sequence from one end of the vessel generation of VLE data. Then we discuss fundamental design
to the other, washing the accumulated solids from the calculations for batch, flash, and continuous column distil-
bottom of the vessel. The fluid velocity from the nozzles lation units. Details of design approaches and related
should be sufficient to entrain 1-mm sand particles. Water developments are given in various available sources [3–6],
should simultaneously be withdrawn from the vessel,
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310 Petroleum Refining and Natural Gas Processing

to the petroleum industries are presented in this chapter. In

general, design equations for all separation equipment (i.e., Vapor

PDF
distillation, absorption, extraction, etc.) are based on two
φ mole
equations: material balance and phase equilibrium. Simul-
taneous solution of these equations leads to general design Tb
equations for these separation units.
Feed
Ts, P

PDF
13.3.1 VLE Data 1 mole
Distillation is based on the separation of compounds
Tb
through vaporization in which lighter (more volatile) compo- Liquid
nents tend to vaporize at lower temperature in comparison

PDF
with heavier (higher boiling point) compounds. Separation 1-φ mole
of compounds continues until the vapor and liquid phases
in contact with each other reach an equilibrium state. Tb

Consider a multicomponent system under the condition

Figure 13.4—Schematic of a single-stage flash distillation unit.
of temperature T and pressure P at which vapor and liquid
phases may coexist together at equilibrium. If the mole frac-
tion of component i in the liquid is shown by xi and in the valve) in which part of the feed is vaporized. The condition
vapor phase by yi, then the equilibrium ratio (Ki) is defined as of T and P in the separator is the key to determining the
level of separation and the amount of vapor (V ) and liquid
yi (L) produced, as shown in Figure 13.4. It is assumed that
Ki = (13.8)
xi the produced vapor and liquid phases are in equilibrium.
For the system shown in Figure 13.4 and for a
Ki is a dimensionless parameter that depends on T, P, and binary mixture, the material balance equation reduces to
the composition of both phases. The simplest form of Ki y = (1 − 1/ϕ) x + xF /ϕ, in which ϕ is the fraction of feed vapor-
is obtained through Raoult’s law, which gives Ki = Pivap/P, in ized (ϕ = V/F) and is a number between 0 and 1. With the
which Pivap is the vapor pressure of component i at tempera- knowledge of the equilibrium relation between the y and x
ture T. Raoult’s law is valid when the liquid is an ideal parameters, ϕ can be determined. If the feed is a continuous
solution and the vapor phase is assumed to be an ideal gas mixture such as crude oil, a probability distribution func-
such as benzene-toluene system under atmospheric pressure. tion (PDF) model can be used to express boiling point (TS)
Calculation of vapor pressure or Ki values for various systems distribution of feed, as shown in Figure 13.4. The amount
of hydrocarbons as well as nonhydrocarbons is discussed of vapor (ϕ) produced and the PDF of products can be
in full detail in ASTM Manual 50 [7]. Examples of a nonideal obtained from the following equations:
∞
system are ethanol-water or acetone-chloroform, in which 1 − KT
they may exhibit azeotrope behavior. As pressure changes, ∫ (1 − φ) + φK FTF dT = 0 (13.10)
T T
so do the equilibrium curves and the boiling point diagram.
In general, with an increase in pressure the equilibrium 1
curves get closer to the diagonal and make separation by FTL = FTF (13.11)
(1 − φ ) + φ KT
distillation more difficult. Knowledge of Ki values or the
equilibrium curve is the first step in the design or operation
KT
of any type of distillation unit. FTV = FTF (13.12)
Equilibrium data may also be presented in terms of the (1 − φ ) + φ KT
relative volatility of A to B, αAB . defined as the ratio of equi-
where:
librium ratios: αAB = KA/KB. At a given pressure, values of
KT = equilibrium ratio of a component with boiling point
αAB vary with temperature and decrease with an increase in
T, and
temperature. For a binary system of A and B, the equilibrium
F = PDF for boiling point.
relation can be expressed in the following form in terms of
Discussion about use of PDF in development of the
an average value of αAB:
above equations is given in Chapter 4 of ASTM Manual
50 [7]. A schematic of a three-stage separator is shown in
α AB xA Figure 13.5, where a crude oil pressure is reduced in three
yA = (13.9)
1 + (α AB − 1) xA stages to atmospheric pressure. The details of calculations
are discussed in Chapter 9 of reference 7. The composition
For systems that follow Raoult’s law, the relative volatility of the liquid from the last stage is the same as crude oil
can be calculated from vapor pressure data: αAB = PAvap/PBvap. ready as a feed to a refinery and was given in Chapter 1
As αAB increases, the equilibrium curve gets farther from the (Table 1.1).
diagonal line and separation by distillation becomes easier.
13.3.3 Batch Distillation
13.3.2 Flash Distillation The simplest form of batch distillation, also known as
Flash distillation is the simplest form of distillation and is differential distillation, consists of a heated kettle or boiler
performed in a unit called a flash separator. The feed enters and a condenser to liquefy generated vapor [3–6]. There is
the separator at higher temperature (by passing through a no reflux, and once a certain amount of distillate is pro-
heater) or at lower pressure (by passing through an expansion duced, the remaining liquid in the vessel can be withdrawn
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Copyright ASTM International

AST-MNL58-11-0801-013.indd 310 3/12/13 2:24 PM

Chapter 13 n Design Aspects of Separation Units and Processing Equipment 311

GAS 1 GAS 2 GAS 3

RESERVOIR
Stage 1 Stage 2 Stage 3
FLUID
P=21.7 bar P=5.2 bar P=1.01 bar
P =164.5 bar LIQUID 1 LIQUID 2
T=37.8°C T=35°C T=32.2°C
T = 118.3°C

LIQUID 3
(Crude Oil)

Figure 13.5—Schematic of a three-stage separator in a Middle East production field.

as a bottom product (rich in heavy compounds). Assume whereas a total condenser does not increase purity of the
a binary liquid mixture of A and B exists in batch flask distillate. Likewise, the reboiler acts as an ideal tray or
in which the initial amount of liquid is no moles with a stage because vapor returning to the column is in equilib-
composition of xAo = nAo/no (mole fraction). At any time rium with the bottom product (Figure 13.6).
during the vaporization process, the number of moles of The reflux ratio is the ratio of the rate of reflux to the
liquid remaining in the vessel is n with composition xA rate of distillate (R = L/D), and with an increase in reflux the
and no – n moles of distillate with an average composition of quality of product increases. However, as the rate of reflux
yA,avg = (nAo– nA)/(no– n). The highest separation occurs at an increases, the amount of heat required for the reboiler also
initial time when yA,avg is at its highest value but the amount increases, which causes an increase in the operating cost
of distillate (product) is insignificant. Through material while decreasing the capital cost. The optimal reflux is cho-
balance and equilibrium relation, we obtain the following sen when the total cost is at a minimum [4]. The operating
relation for calculation of xA. reflux ratio is always greater than the minimum reflux at
which the number of trays or the column height is infinity.
no 1  x (1 − xAo )  1 − xAo  The feed divides the column into two parts of enriching
ln = ln  A  + ln   (13.13)
n α AB − 1  xAo (1 − xA )   1 − xA  (above the feed) and stripping (below the feed) sections.
The basic design of such columns involves the calculation
Another form of this equation can be derived between of the number of trays and the height and diameter of the
moles of A and B remaining in the vessel as column. Calculations for determining the number of ideal
trays (Nth) are available in various sources [3–6].
nA n  Selecting the operating conditions of a distillation
ln = α AB ln  B  (13.14)
nAo  nBo  column is a key part of the process. First, the operating
pressure will fix the VLE data. As stated previously, lower
operating pressures tend to make separation easier because
For example, for an initial mixture of 60 moles benzene and the equilibrium curves are further apart, resulting in higher
40 moles toluene distilled in a pot to reduce the benzene relative volatility. The following considerations should be
concentration to 30 mol % at 1 atm pressure, the tempera- evaluated when selecting the operating conditions of a
ture changes from approximately 85ºC to 105ºC, at which distillation column:
an average value of αAB calculated from the vapor pressure is • What condenser cooling medium will be used? The
approximately 2.4. From the above relations, we get n = 65.5 column top pressure will be the vapor pressure of the
moles and xA = 0.3 whereas the distillate (34.5 moles) has a overhead product. It can be raised slightly with blanket
composition of yA,avg = 0.855. If we had to use one-stage flash gas or reduced slightly if a subcooling condenser is
distillation to produce the same amount of distillate, then the used. For most columns it is typical to set the overhead
composition would be yA = 0.731. This indicates that batch dis- condensing temperature to no less than 10°C above the
tillation has better separation efficiency than flash distillation. maximum supply temperature of the cooling medium.
Using air-cooling will result in higher operating pres-
13.3.4 Distillation with Reflux—Binary Systems sures than using cooling water. Refrigeration is not
The separation of components in a distillation process advisable unless absolutely necessary because of the
increases with returning a portion of liquid distillate to the high capital and operating costs.
distillation column, known as reflux, as shown in Figure 13.6. • At the selected operating pressure, is the bottoms tem-
Distillation columns are designed with the use of equipment perature required to boil the bottoms product (or feed
to promote contact between vapor and liquid in the column. in the case of a feed furnace heated column) compatible
These devices are various types of trays or packing. An with the bottoms product? Could it result in decomposi-
ideal tray or a theoretical stage is a device at which vapor tion via cracking or coking of the fluid? If so, reducing
and liquid leaving the stage or tray are in equilibrium and the operating pressure and temperature will be neces-
the maximal separation of components can be achieved.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
sary either by using a colder condensing medium or
A partial condenser (Figure 13.6) operates as an ideal stage operating at vacuum using ejectors or vacuum pumps.
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312 Petroleum Refining and Natural Gas Processing

qC1 qC2 Distillate

D (mol/h)
XD
qD
Partial Total
Condenser Condenser
1
Enriching Reflux
(Rectifying) 2 R
section

Feed
F (mol/h)
XF
qF

Stripping
section

Bottoms
B (mol/ h)
XB
qB

Reboiler q
R

Figure 13.6—Continuous distillation column with reflux for a binary system with a partial condenser.

• What heating media are available for reboilers? If that will operate near the cricondenbar because the latent
steam is available at 150°C and 250°C, then it is more heats are very small, the density difference between
energy-efficient to use the lower-pressure steam source; liquid and vapor are small, and relative volatilities are
therefore, avoiding a pressure that results in a reboiler small. This is a common design consideration with
temperature of 155°C is advisable. cryogenic demethanizer columns.
• Are there external constraints on operating conditions, The graphical method of McCabe-Thiele is most
such as major compression requirements (a la deep widely used to determine N for binary systems, as shown
cut natural gas liquids [NGL] plants) that drive higher in Figure 13.7 for a benzene-toluene system at atmo-
operating pressures? Caution is advised with columns spheric pressure. The compositions (mole fraction of light

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 13.7—Number of theoretical trays in a distillation column according to McCabe-Thiele method for a binary mixture of
benzene and toluene.
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 313

component) in the feed, distillate, and bottom products the minimum reflux ratio Rmin, at which the number of trays
are shown by xF, xD , and xB, respectively. In this example, is infinity. The operating line in the enriching section at
the feed enters as saturated liquid with xF = 0.5, and it is Rmin can be drawn from a diagonal at xD to the intersection
desired to have 50 % of feed as distillate with xD = 0.9 and R of the q-line of the equilibrium curve. If this line continues,
= 1.43. Composition of distillate and bottom products can then it intersects with the y-axis, at a point that gives the
be determined from material balance. If molar rates (i.e., value of xD/(Rmin + 1) from the y-axis reading.
mol/h) of feed, distillate, and bottom products are shown
by F, D, and B, respectively, then F = D + B and FxF = DxD + 13.3.5 Distillation of Multicomponent Systems
BxB. From the material balance, the bottom composition is If the feed to a distillation column has more than two com-
xB = 0.1. The enriching operating line originates from the ponents, then the procedure to determine the number of
diagonal at xD with a slope of R/(R + 1) or an intercept of trays is somewhat different [3–6]. Separation of a mixture of
xD/(R + 1). This line intersects with the feed line, at which three components (A, B, and C, in which C is the heaviest
it is connected to the intersection of xW with a diagonal. component) by two distillation columns in series is demon-
The feed line is originated from a diagonal (at xF) with a strated in Figure 13.8, where C is mainly separated in the
slope of q/(q − 1), where q is the feed quality and is defined first column and A and B in the second column.
as q = (Hv − HF)/(Hv − HL), where HF is the enthalpy of feed Consider that a mixture of four components, A, B,
and (Hv − HL) is the heat of vaporization for the feed. If C, and D (ordered from light to heavy as boiling point
the feed enters as saturated liquid, then HF = HL and q = 1 increases or K value decreases), is fed to a distillation
whereas if it enters as saturated vapor, then q = 0. Accord- column with a reflux. The first step is to get the K values for
ing to Figure 13.7, the number of ideal stages is 8.6, and if all compounds at the operating pressure and temperature
a total condenser is used, then the number of ideal trays is of the column on the basis of the methods available as given
determined by subtracting 1 for the reboiler and we obtain in Chapter 6 of ASTM Manual 50 [7]. As the temperature
Nth = 7.6. Because actual plates are not ideal, the number of in the column varies, the K values may be determined
real plates (N) is greater than 7.6, and that depends on the at two temperatures: the temperature in the condenser
overall efficiency of the column, EO , as given in Eq 13.15: (dew point of distillate) and in the reboiler (bubble point
of bottom product). The second step in solving a multi-
Nth component distillation problem is to identify two key
N= (13.15)
EO components designated as a heavy key (HK) and light key
(LK), which both appear in appreciable amounts in top
In this equation, Nth represents the number of theoretical and bottom products. Then, for all components, relative
trays not counting the reboiler and partial condenser. volatility with respect to HK should be determined as αi =
Calculation of overall efficiencies (EO) will be discussed Ki /KHK, in which we always have αHK = 1, and for the LK
later. αLK = KLK/KHK. Once the values of αLK at the top and bottom
temperatures of the column (at condenser and reboiler
13.3.4.1 Calculation of Minimum Number of temperatures) are determined, the average value of αLK can
Trays be determined from
As the reflux increases, the operating line of the enriching

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
section approaches diagonal because the slope of the line α LK , avg = α LK , top α LK , bottom (13.17)
R/(R + 1) increases with an increase in the value of R. As
the operating lines get closer to the diagonal (45º line), the
The Fenske equation (Eq 13.16) can then be used to cal-
number of trays gets smaller and smaller (see Figure 13.6).
culate the minimum number of theoretical stages (at total
For total reflux that is D = 0, we have R = ∞, which cor-
reflux, R = ∞):
responds to the operating line with a slope of unity.
Therefore, for the case of minimum plates, both operat-
ln [( DxD / BxB ) LK /( BxB / DxD )HK ]
ing lines lie on the diagonal, and feed composition and Nmin = (13.18)
its quality do not affect the minimum number of trays. For ln (α LK , avg )
cases in which the equilibrium data can be represented by
an average value of relative volatility (αAB), the minimum After the initial round of calculations, the composition of top
number of theoretical stages can be calculated analytically and bottom products can be modified using the following
through the Fenske equation, which was proposed in 1932
and is shown in Eq 13.16 [4].
A, B A
ln [ xD (1 − xB ) / xB (1 − xD )]
Nmin = (13.16)
ln (α AB )
FEED
To know the minimum number of ideal trays in the column 1 2
excluding the reboiler, Nmin as calculated from the above A, B, C
equation should be reduced by 1.

13.3.4.2 Calculation of Minimum Reflux

Ratio C B
The optimum reflux can be determined by minimizing the
total cost (operating + fixed capital costs). However, the Figure 13.8—Separation of a three-component mixture by two
actual and operating reflux is usually expressed in terms of
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314 Petroleum Refining and Natural Gas Processing

relation until no significant changes are observed in the To solve this problem, we assume that all butane appears in
composition: the distillate and all heptane appears in the bottom product.
Pentane is the LK and hexane is the HK component. From
 xi  Nmin  x  material balance calculations, the compositions of distillate
  = (α i , avg )  i  (13.19)
 xHK D  xHK B and bottom products are calculated as given in Figure 13.9.
Top and bottom temperatures are then calculated from
To calculate the total number of theoretical stages at an dew point and bubble point calculations as Ttop = 64ºC and
operating reflux value of R, the method of Underwood can Tbottom = 133 ºC. Therefore, the average column temperature
be used. In this method, Rmin is calculated from is 98.5ºC. At this temperature, we obtain αLK,avg = 2.3. Using
Eq 13.18, we calculate Nmin = 7.2 and from Eq 13.20 we
 α ( x ) obtain Rmin= 0.505. At R = 1.3, Rmin = 0.657, and from Eqs
Rmin = ∑ i iD  − 1 (13.20) 13.22 and 13.23 we get Nth = 16.8, Ne/Ns = 1.187, and Ne = 9.1
 i αi − θ  (feed enters on the 10th tray). Similar calculations can
be performed by a HYSYS simulator [8] with use of the
in which parameter θ is determined from solving the fol-
Peng-Robinson equation of state. With this, we obtain
lowing relation:
bottom product B = 35.25 mol/h, xA,B = 0.00019, xB,B = 0.03552,
α i xiF xC,B = 0.539, xD,B = 0.4253, Tbottom = 130.5 ºC, Rmin = 0.485,
∑α = q −1 (13.21) Nmin = 7.4, Nth = 17.5, and Ne = 9.4, which are close to the
i −θ
i
values calculated through the above methods. If the feed
to the column is a crude oil or an undefined petroleum
where q is the feed quantity defined earlier. Once Rmin is mixture, then a distribution model can be used to represent
known, Nth can be determined from the Gilliland correla- the mixture with several pseudocomponents with known
tion using input data of Nmin, the value of R at operating composition and characteristic properties as discussed in
conditions, and Rmin. The Gilliland correlation is usually Chapter 4 of ASTM Manual 50 [7].
expressed in a log-log graphical form, but the following
relation developed based on the correlation represents
13.3.6 Energy Requirement for a Distillation
the original data fairly well and can be used for practical
Column
purposes [6]:
The main operating cost for a distillation column is the cost
 1 + 54.4Ψ   Ψ − 1 for the energy required in the reboiler. High-pressure steam is
Nth − Nmin typically used in the reboiler to partially vaporize the liquid
= 1 − exp    0.5  (13.22)
Nth + 1 11 + 117.2Ψ   Ψ  from the bottom of column. The rate of energy required
is designated by qR (e.g., kJ/h, kW, MMBtu/h) and can be
where: determined through overall energy balance around the
Ψ = (R – Rmin)/(R + 1) and column shown in Figure 13.6. If the enthalpy of feed, distil-
Rmin is calculated from Eq 13.20. late, and bottom products are shown by hF, hD, and hB
The value of R is usually given in terms of Rmin (i.e., (i.e., kJ/mol), respectively, and the energy removed from the
operating reflux is 30–50 % higher than its minimum). condenser is shown by qC, then the overall energy balance
Finally the feed-plate location is determined from gives the following relation for calculation of qR:

  Bx  
2
qR = DhD + BhB + qC − FhF (13.24)
Ne x
log = 0.206 log  HK , F   LK , B   (13.23)
Ns  xLK , F  D  xHK , D  
  hD and hB are enthalpies of saturated liquid as they
leave condenser and reboiler at the corresponding tem-
where: peratures. Calculations of the enthalpy of petroleum
Ne and Ns = number of theoretical stages in the enriching and fractions are discussed in Chapter 7 of ASTM Manual
stripping sections, respectively, and xHK,F = mole fraction of 50 [7]. The mass rate of saturated steam required for
the HK component in the feed. the reboiler can be calculated from qR/λs, in which λs is
Other compositions are similarly defined. In Eq 13.23, the latent heat of steam. The amount of energy removed
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Ne gives the number of theoretical stages above the feed tray from the condenser (e.g., via cooling water), qC, can be
and Ns does include a reboiler as one theoretical stage or tray. calculated through an energy balance around the total
Ne and Ns can be determined from simultaneous solution condenser as
of Eq 13.23 with Nth = Ne + Ns, where Nth is calculated from
Eq 13.22. qC = D ( R + 1) ( H1 − hD ) (13.25)
As an example, consider the feed to a distillation
column operating at 4 atm consisting of 100 mol/h of a where H1 is the enthalpy of saturated vapor leaving the top
mixture of 40 % n-butane, 25 % n-pentane, 20 % n-hexane, of the column and entering the condenser (Figure 13.6),
and 15 % n-heptane (all in mol %). The feed enters at its which has the same composition as distillate product (xD).
boiling point and is distilled so that 95 % of the n-pentane In fact, in the above equation, (H1 – hD) is the latent heat
is recovered in the distillate and 95 % of n-hexane in the of product D in kilojoules per mole. D(R + 1) is equivalent
bottom product. The following should then be calculated: to V1 or the molar rate of vapor entering the condenser.
(1) the amount and composition of distillate and bottom The mass rate of cooling water required depends on the
products, (2) Nmin and Rmin, and (3) Nth and the feed-tray decrease in temperature of water (ΔT) and can be calculated
location at an operating reflux ratio 30 % higher than Rmin. through water heat capacity as qc/(CpΔT).
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 315

D, xD
D = 64.75 (mol/h)
n-butane = 61.8 %
n-pentane = 36.7 %
n-hexane = 1.6 %
n-heptane = 0.01 %
P = 405.3 kPa T top = 54.6 ºC

F, xF

F = 100 (mol/h)
n-butane = 40 %
n-pentane = 25 %
n-hexane = 20 %
n-heptane = 15 %
B = 32.25 (mol/h)
Feed at boiling point (q=1)
n-butane = 0.02 %
n-pentane = 3.6 %
n-hexane = 53.9 %
n-heptane = 42.5 %
T bottom = 130.5 ºC
B, xB

Figure 13.9—Material balance calculations for multicomponent distillation column design.

As an example, consider a distillation column operating (B) the liquid level in the column can be controlled to avoid
at atmospheric pressure with a feed of 100 moles of equi- flooding. The distillate product quality and composition are
molar mixture of benzene and toluene with xD = 0.9, xF = 0.5, controlled by manipulating the reflux ratio (R) as discussed
and xB = 0.1 as presented in Figure 13.6. in reference 5.
Enthalpies of saturated liquid and vapor for a benzene-
toluene binary system are given in reference 5. On the basis
13.3.7 Column Efficiency
of such data, the following expression can be obtained for the
As was stated through Eq 13.15, the number of trays
enthalpy (H) of saturated vapor of a mixture of benzene-
calculated through the above methods is based on the
toluene with a mole fraction of benzene as y H = 38.45 –
assumption that each tray or each stage (for the case of
7.246y – 0.396y2, where H is in kilojoules per mole. Likewise,
packed columns) behaves as an ideal stage. Vapor and
for a saturated liquid mixture, the following expression well
liquid leaving an ideal tray are in equilibrium; however,
represents the data: h = 5.1 – 8.0816x + 2.99x2, where h is
for an actual tray as shown in Figure 13.10 the vapor
the liquid enthalpy. At xD = 0.9, xF = 0.5, and xB = 0.1, we get
phase is not in equilibrium with liquid on the tray. For
H1 = 31.6, hF = 1.81, hD = 0.248, and hB = 4.32 kJ/mol. The
example, consider a tray column as shown in Figure 13.6
reference state for the enthalpy values is saturated liquid
or Figure 13.10 in which vapor comes to the nth tray from
benzene (xD = 1) at 1 atm in which enthalpy is considered
the lower tray (n + 1) with composition yn + 1 and leaves the
as zero. From Eq 13.25 with R = 1.43 and D = 50 mol/h,
nth tray with composition yn. If the liquid leaving the nth
qC = 3809 kJ/h (1.06 kW) and from Eq 13.24 we get qR =
tray has a composition of xn and the composition of vapor
3856 kJ/h (1.07 kW).
in equilibrium with this liquid is shown by yn*, then for
The heat input to the reboiler (qR) and the heat removal
an ideal or theoretical tray yn = yn*. However, in practice,
(qC) from the condenser are among the variables that can be
trays are not ideal and vapor composition is less than the
manipulated to control the column. In general, in a distilla-
equilibrium composition: yn < yn*. This is the basis for the
tion column, the variables that can be manipulated to control
definition of tray efficiency known as Murphree efficiency
the column are R, D, B, qR, and qC. With qR, one can control the
(EM), defined as
bottoms composition (xB) and temperature whereas with qC
the tower pressure can be controlled. With the distillate rate
yn − yn + 1
(D), the distillate product composition (xD) and liquid level EM = (13.26)
in the accumulator is controlled and with the bottom rate yn* − yn + 1
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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AST-MNL58-11-0801-013.indd 315 3/12/13 2:24 PM

316 Petroleum Refining and Natural Gas Processing

Condenser

Cooling

Vapor Accumulator

Overhead product
Reflux

Feed Sieve tray

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Vapor

Liquid Bottom liquid product

Steam

Figure 13.10—Vapor liquid contact in a sieve tray distillation column.

Murphree efficiency varies from tray to tray and is different of column efficiency for tray columns are between 40 % and
from the overall column efficiency, defined as the number 80 %. Another widely used empirical correlation to estimate
of theoretical trays to the actual tray (see Eq 13.15). The the overall efficiency is
Murphree efficiency can be used to construct a curve that
represents the actual yn and not the equilibrium curve Eo = 19.2–57.8log(μL) (13.28)
presented by yn*. This is demonstrated in Figures 13.7 and
13.11, where the McCabe-Theile method is used to obtain For absorption tray columns, the overall column efficiency
the actual number of trays. For example, if EM = 0.5 and a Eo (in %) can be estimated from
quasi-equilibrium curve is used instead of a real equilibrium
curve, we get 17.5 – 1 or 16.5 actual trays without including log Eo = 1.597 – 0.199 log(mML μL/ρL)
the reboiler step, which is always equivalent to one theoreti- – 0.0896[log(mML μL/ρL)]2 (13.29)
cal step as shown in Figure 13.10. In this way, we obtain N
= 17 and Nth = 7.5 (without reboiler). The actual number of where:
trays should always be rounded to the higher number. For μL = average viscosity of liquid in cP (mPa.s),
example, for this example it is 17 trays plus a reboiler. ρL = liquid density in lbm/ft3 at average tower temperature
Because this method of determining the actual number (if ρL is in kg/m3, then it should be divided by 16.02 to have
of trays is tedious, inconvenient, and not practical for multi- it in lbm/ft3),
component systems, a simple analytical expression of Brad- ML = average molecular weight of liquid, and
ford, Drickamer, and O’Connell is recommended as [3,9] m = slope of the equilibrium curve (or line).
The above equation cannot be applied to distillation
Eo = 0.492(μLαLK,avg)−0.245 (13.27) columns because m is not constant along the tower. The aver-
age error for this equation is approximately 16 %. Typical
where: values of Eo for absorption columns are between 10 and
μL = viscosity of liquid feed and 30 % and are normally within the range of 1–50 % [10].
αLK,avg = average relative volatility of light to heavy component. The efficiency of packed columns is discussed in the next
The above equation is suitable for sieve and valve tray Section 13.3.8 where height equivalent to a theoretical plate
Copyright ASTM International and gives an average error of ±10 %. Typical values
columns (HETP) is discussed.
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 317

Figure 13.11— Use of Murphree efficiency in the calculation of the actual number of trays for the distillation column of
F

A recent article by Kister [11] examines factors that separation can occur in the reboiler because it acts like
affect overall tray efficiency when designing a new distil- an ideal stage. Having a higher reflux rate can increase
lation column or revamping an existing commercial-scale the purity of top products; however, it reduces the rate of
fractionator. In summary, parameters that affect tower product and requires higher energy in the reboiler. When
efficiency include VLE data such as relative volatility, reflux the column is operating at total reflux, the number of trays
ratio, viscosity of fluid, tower geometry such as flow path becomes a minimum and column length is minimized
length, fractional hole area, hole diameter, and weir height. whereas the operating cost is infinity.
Most efficiency test data reported in the literature were Performance of a distillation column largely depends on
obtained at total reflux; however, the reflux ratio has been the type of equipment used to bring into contact vapor and
reported to have a small effect on tray efficiency. In general, liquid along the column. This can be done through trays
tray efficiency increases with lower viscosity and relative or packings. Behavior of a sieve tray column is shown in
volatility (see Eq 13.27). Viscosity is important because of Figure 13.10. Trays are made of metal plates with holes on
diffusivity because more turbulent mass transfer, thinner them for passing vapor. Liquid on a tray is held by weir and
liquid, and vapor films give better liquid mass transfer coef- moves downward from one tray to the lower tray through
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

ficients. At very low relative volatility (α < 1.2), small errors in the downcomer at the end side of the tray and by gravity
VLE data have a huge effect on tray efficiency. For instance, force. The minimum height of weir is approximately 0.5 in.
at α = 1.1, a –3 % error gives a tray efficiency 40–50 % whereas 1- to 3-in. height is quite common. The height of the
higher than its true value. Because the accuracy of VLE downcomer and weir has a direct effect on column flooding
data is seldom better than 2–3 %, in low-volatility systems and overall efficiency. An ideal tray is a tray in which the
tray efficiencies become meaningless unless accompanied vapor and liquid leaving from that tray are in thermody-
by actual VLE data. However, for α > 1.5–2.0, VLE errors namic equilibrium and the maximal possible exchange of
have a small direct effect on tray efficiency. This applies to components has occurred on that tray. Because there is no
tray and packed columns. Pressure also has little effect on ideal tray, the efficiency of a tray is defined so as to quantify
tray efficiency; for example, as column pressure increases how far a tray is from an ideal tray. For this reason, the
from 10 to 30 bar for isobutane-n-butane systems, efficiency number of actual trays is always greater than the number of
decreases from 105 to 90 %. Literature sources also indicate ideal or theoretical trays determined based on the assump-
that tower geometry has a major effect on the efficiency. tion that trays are ideal. There are different types of trays,
For example, as flow path length increases from 300 to with the most common types being sieve trays, bubble-cap
1500 mm, the overall tray efficiency for a cyclohexane-n- trays, and valve trays. In an industrial scale, sieve and bubble-
heptane system increases from 65 to 100 % [11]. cap trays are shown in Figure 13.12a [12,13]. Sieve trays
cost less than valve trays by 20 %, and bubble-cap trays
13.3.8 Column Types and Operational Aspects normally cost 3–4 times more than valve trays. The major
A schematic of a distillation column with a partial condenser difference in a valve and sieve tray is the pressure drop
is shown in Figure 13.6. The top condenser is a partial across the plate. As shown in the figure, the size of the hole
condenser to obtain liquid for the reflux, and the product in the sieve tray is approximately 1/ 8 to ½ in. with 3/ 8 in. as
is condensed in a second condenser. The first condenser an average size of a hole. As a rule of thumb for sieve trays,
plays like a single equilibrium stage or a tray. The bottom the total hole area of a plate is approximately 5–15 % of the
liquid is also partially vaporized in a reboiler, and a further
Copyright ASTM International total column area. In bubble-cap trays, there is a riser in
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318 Petroleum Refining and Natural Gas Processing

(a)

Sieve Trays, 1800mm Ø Dephosgenation Column Bubble Cap Trays, 1800mm Ø Vacuum Flash Tower

(b)

Pall Rings in Metal Pall Rings in Plastic

DMTP High Performance Random Packing in Metal

DMR High Performance Random Packing in Metal

Ceramic Saddles
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 13.12—(a) Two types of industrial scale trays and (b) various packings for industrial use [12]. With permission from [12].

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AST-MNL58-11-0801-013.indd 318 3/12/13 2:24 PM

Chapter 13 n Design Aspects of Separation Units and Processing Equipment 319

the middle of the cap in which gas passes through. The This is done from a few minutes to several days and is
size of a bubble cap is a design parameter, but 3 and 6 needed to stabilize the column, condenser, and reboiler.
in. are common sizes, and for a column of 7 ft. approxi- Some common problems during operation of a distillation
mately 22 rows of 3 in. or 8 rows of 6-in. caps are needed. column are [16]
However, 3-in. caps are more efficient, but because of cost • Tray damages due to corrosion or poor installation.
considerations 6-in. caps are preferable [14]. • High liquid level in the column and flooding. For this

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
As the name implies, a sieve tray is a simple plate with reason, the lower trays must be made with extra strength.
a series of holes on the tray where the gas goes through. • Water comes from feed or steam injected into the col-
In valve trays, a contact device moves with the gas and if umn and causes problems such as corrosion, pressure
there is no gas, then the valves are closed, preventing liquid surges, flooding, and hydration.
from dropping through the holes. One problem with sieve • Hydrate (loosely bonded mixtures of hydrocarbons and
and valve trays is weeping, which is flow of liquid through water) formation causes problems such as plugging of
g
as-opening holes. Weeping is mainly associated with sieve tubes. Hydrates are solids, and low temperature, high
trays and reduces the tray efficiency when it occurs. In gen- pressure, and turbulence promote formation of hydrates.
eral, sieve and valve trays are more efficient than bubble-cap Usually when a column is operating at 30–40°F, hydrates
trays and less expensive, but weeping is a problem. Sieve may form, and dehydration equipment or materials are
trays are the least expensive kind of trays; however, the needed. A similar problem exists with wax formation at
liquid flow and gas flow rates must be under control and low temperatures, and adding components to the feed to
within a narrow range to prevent weeping. lower the freezing point will help to prevent hydration
An alternative to tray columns is packed towers, which or wax formation.
are filled with particles called packing. Columns can have • Leaking in heat exchangers, which sometimes cause
structured or random packing. These kinds of columns are reactions with other streams and difficulties in opera-
usually used for columns with diameters less than 2 ft (0.6 m) tion of the column.
and usually for absorption columns, although they can also be • During flooding, the plant must be shut down to clean
used for distillation columns. The most common types of pack- the column and to remove blockages. Online cleaning
ings are raschig ring, berl saddle, intalox (metal), intalox saddle includes use of antifoam injection and solvent injection
(ceramic), tellerette, or pall ring, as discussed in reference 6. to dissolve frozen particles. Changes in feed composi-
Samples of such packings are shown in Figure 13.12b [12]. tion and reducing the plant load may also help to pre-
Usually 1.5- and 2-in. (37 and 50 mm) sizes are used, but they vent flooding.
should always be less than 1/10 of the column diameter. • Foaming is a problem with formation of foams. These
The main characteristic of a packing is to have high are vapors that do not separate from liquid and usually
surface area with less volume. Liquid flows over packings occur in the stripping section of a distillation column
and forms a thin film in which gas passes over the film as well as absorption columns. The life of a foam is just
and exchange of components occurs. Packings are made of few seconds, and antifoam materials (such as dimethyl-
ceramics, plastics, or metals with good mechanical strength silicons) may be used to prevent foaming. If the bottom
so that they do not crush or powder. Metallic packings are product of a distillation column has lower surface
mainly used in petroleum and natural gas units, whereas tension than its top product, then foaming is unlikely.
plastics are used in absorption and stripping columns
operating below 120°C. They must be resistant to thermal 13.3.9 Column Size Calculations
degradation and not reactive to gas and liquid flowing in the Design calculations for a distillation column mainly involve
column. Packed columns are less expensive than tray col- calculation of the height and diameter of the column. The
umns and must show low pressure drop and liquid hold-up. way these column dimensions can be calculated for tray
On top of a packed column there is a distributor to distribute and packed columns is summarized below.
liquids and prevent channeling within the column. Some
advantages of packed columns over tray columns are dis- 13.3.9.1 Tray Columns
cussed in Section 13.3.9.3. For tray columns, the height is calculated from the follow-
A new distillation column should go through “column ing relation:
commissioning,” which is a series of operations before col-
umn startup. These include removing undesirable materials hc = (Nact − 1) hs + Δ h (13.30)
in the column through air or N2 blowing, pressurizing the
column to detect any leaks, and washing to remove dirt. After in which hc is the height of the column, Nact is the actual
commissioning, the column is brought to its normal pressure number of trays in the column, and hs is the tray spacing.
followed by heating (if needed) and then feed is introduced Δ h is the additional height required for the top and bottom
gradually to a normal feed rate. One major problem during of the column and should not be less than 2hs. Tray spacing
the operation of a distillation column is flooding, which is due varies with the column diameter and number of trays. It
to accumulation of liquid on trays. Flooding can be detected usually varies from 0.15 m (6 in.) to 0.9 m (36 in.). For
when there is a drop in the bottom product and a sudden columns more than 1 m in diameter, a spacing of 0.3–0.6
increase in pressure drop along the column. Once flooding m will be normally used. A typical value for tray spacing is
occurs, the liquid must be removed as liquid (pumped off), as 0.5 m; however, when the number of trays is so large, the
it will not be possible to boil off the excess [15]. height should be limited because of external constraints
Sometimes it is necessary to operate the column with such as the ceiling of a building. For small column diame-
total reflux, which means no product with feed interruption. ters, a smaller tray spacing may be used. A larger spacing is

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320 Petroleum Refining and Natural Gas Processing

required between certain plates that feed enters or there is a V ( kg / h) 1 1

side stream product and for manways into the column [10]. Ac (m2 ) = × × (13.34)
3600 ( s / h) ρ V ( kg / m3 ) vmax, design (m / s)
To calculate the diameter of a tray column, the maximum
allowable vapor velocity (vmax) in the column is first deter-
mined from Finally, the column diameter, dc, is calculated from Ac as

σ 
0.2
ρ L − ρV 4 Ac
vmax = K v   (13.31) dc = (13.35)
 20  ρV π

where:
13.3.9.2 Packed Columns
σ = surface tension of liquid in dyn/cm (mN/m),
For packed columns, the height is calculated from the fol-
ρL = liquid density in kg/m3 or lbm/ft3, and
lowing relation:
ρV = vapor density in kg/m3 or lbm/ft3.
A typical value of σ for organic liquids is approximately
hc = Nth(HETP) (13.36)
20–25 mN/m and for water is 72 mN/m. Calculations of σ,
ρL, and ρV are discussed in ASTM Manual 50 [7]. At moder-
in which Nth is the theoretical number of stages (excluding
ate column pressures, ρV can be calculated from the ideal
reboiler) and is basically calculated the same way as the
gas law using the average molecular weight of gas and the
number of theoretical trays. HETP is the height equivalent
column temperature. The value of KV is in ft/s and should
to a theoretical plate and is in fact the height of the packed
be obtained from Figure 13.13, where L and V are the flow
column, which can give a separation equivalent to one
rates of liquid and vapor, respectively, in the column in kg/h
theoretical plate. In Eq 13.36, hc is in fact the height of the
or lbm/h. Another relation for approximate calculation of
column that is filled with packing. The real height of the
vmax without use of the figure is given as [10]
column is higher considering the top and bottom portions
of the column. HETP depends solely on the packing size
ρ L − ρV as given in Eq 13.37 in SI and English unit systems for
vmax = (−0.171 hs2 + 0.27 hs − 0.047) (13.32)
ρV random-packed towers [3]:

where:
HETP (m) = 0.018 dP (mm)
hs = tray spacing (m), and (13.37)
vmax = maximum vapor velocity (m/s). HETP ( ft ) = 1.5 dP ( in)
The calculated vapor velocity (vmax) from Eq 13.32
should be revised for the downspout area (91 %), foaming in which dP is the packing diameter. If the tower diameter
(95 %), and flooding (80 %) as follows: is less than 0.6 m but not less than 0.3 m, then it can be
assumed that HETP = dc. For vacuum distillation, it is sug-
vmax, design = (0.91) (0.95) (0.8) vmax (13.33) gested to add 0.15 m to the predicted values of HETP. Some
other researchers have developed slightly different relations
The tower cross-sectional area (Ac) is then calculated from in which HETP is predicted from the column diameter (dc)
the vapor flow rate (V) and vapor density (ρV) as as given in Eq 13.38 [9]:
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 13.13— Estimation of Kv for tray columns [10].

AST-MNL58-11-0801-013.indd 320 3/12/13 2:24 PM

Chapter 13 n Design Aspects of Separation Units and Processing Equipment 321

 dc for dc ≤ 0.5 m pressure drop in the column. According to this method, if

 pressure drop is known, G can then be calculated from the
0.5dc 0.3 for dc > 0.5m gas flow rate (V), and the area of cross section Ac can be
HETP =  0.3 (13.38)
 dc for absorption columns calculated as indicated in Figure 13.14. The column diam-


--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
 with dc > 0.5m eter can then be calculated from Eq 13.28. The properties
of gas and liquid phases needed for use of Figure 13.14 can
be estimated from the composition through methods pro-
where HETP and dc are both in metres. Again, for vacuum
vided in ASTM Manual 50 [7]. For the cases in which these
distillation 0.15 m should be added to the predicted values
values significantly vary from top to bottom of the column,
of HETP. For structured-packed towers the relation is
a separate diameter can be calculated for the bottom that is
HETP = 100/a + 0.1 (13.39) different from the top.
To calculate Ac from Figure 13.14, the pressure drop in
in which HETP is in metres and a is the surface area of the column for the gas phase per unit length of packed
packing in metres squared per cubic metres. HETP in column must be known. The recommended pressure drop in
structured-packed towers is usually less than that of random- packed columns for atmospheric- and high-pressure separa-
packed towers and is in the range of 0.3–0.6 m (1 to 2 ft). tions ranges from 400 to 600 Pa/m, for vacuum operation
Values of a depend on the type of packings and vary from between 4 and 50 Pa/m, and for absorption/stripping
200 to 700 m2/m3 for structured packing as given in refer- columns between 200 and 400 Pa/m [9]. The conversion
ence 3. For random packing, values of a are less than those factor for such pressure drop from an English-unit system
for structured packing. However, most structured packings is 1 in. H2O/ft height = 83.33 mm H2O/m height = 817.13 Pa/m
have surface areas in the range of 200–300 m2/m3 and for height [7]. For absorption columns, a typical value for pres-
random packing in the range of 100–200 m2/m3. The void sure drop is 0.25 in. H2O/ft, which is nearly equivalent to
fraction (volume of empty space to volume of column) for 200 Pa/m. The minimum pressure drop is approximately
various packings is in the range of 0.9–0.97. 50 Pa/m, and the packing factor, FP, given in Figure 13.14
To calculate column diameter for packed columns, a mainly varies with packing size; however, it also slightly
similar method as that of tray columns may be used but varies with packing type. More data on packing factor are
using different correlations for gas-phase mass flux (G) and given in reference 5.

Figure 13.14—Flooding and pressure drop correlation for packed columns—calculation of column diameter [9].
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322 Petroleum Refining and Natural Gas Processing

13.3.9.3 Advantages and Disadvantages of VN+1 y1

Tray and Packed Columns
Advantages of tray columns can be summarized as follows
[9,10]: Loxo
• Design calculations for tray columns are more reliable
than those for packed columns. 1
• Tray columns can be used to handle a wide range of
liquid and vapor rates without flooding. Lox1
• Plates are more accessible for cleaning than packings, VN+1 y2
especially when liquid contains dispersed solids. 2
• The total weight of a dried tray column is less than that
of a packed column.
• It is easier for tray columns to make provisions for side
streams.
• Packed columns are not used when the column diameter N-1
is larger than 1.5 m, and tray columns are not used when
the diameter of the column is less than 0.6 m (2 ft). VN+1yN LoxN-1
• Packed columns are less expensive than tray columns
and easier to construct, especially when handling cor- VN+1yN+1 N
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

rosive liquids.
• Packed columns are preferred when the liquid has a
LoxN
tendency to foam.
• The amount of liquid hold-up in packed columns is
Figure 13.15—General schematic of a multistage gas absorption
less than that of tray columns. column.
• The pressure drop in packed columns is less than that of
tray columns and is more suitable for vacuum columns.
relation between yi and xi is given through the equilibrium
Use of a packed column is more common in gas
ratio yi = Ki xi as defined in Eq 13.8. Ki varies with tempera-
absorption towers than distillation columns.
ture, pressure, and composition, although for hydrocarbon
mixtures, composition dependency may be neglected. Esti-
13.3.10 Commercial Simulation Tools mations of Ki, and ki have been discussed in detail in ASTM
The aforementioned methods are manual but are still a Manual 50 [7].
valuable toolkit for engineers to understand how distillation As shown in Figure 13.15, gas enters at the bottom at
calculations are performed. However, for many designers a rate of VN+1 (mol/h) with a composition in terms of mole
and operators, commercial simulation and modeling tools fraction (yN+1). The solvent (usually pure) enters from the
are available to overcome the sheer volume of calcula- top of the column at a rate of L0 (mol/h) with composi-
tions required for a multicomponent column. A very good text tion x1 and leaves at a rate L1 (mol/h) with composition
on this subject is by Kaes [17], which covers many of the x1. Compositions x and y represent mole fractions of a
common refinery units that can be modeled in commercial component distributed in the liquid and vapor phases,
thermodynamic simulators. Many of these simulators also respectively. The overall and component material balances
have shortcut methods to estimate the dimensions of the (in moles) can be written as
column using various published correlations such as those
discussed above. L0 + VN + 1 = LN + V1 (13.40)
Additionally, many suppliers of column internals offer
software for rating or sizing columns using their proprietary L0 x0 + VN + 1 yN + 1 = LN xN + V1 y1 (13.41)
internals. An independent option is available for firms that
are members of Fractionation Research, Inc. (www.fri.org), If the solvent is pure, then x0 = 0, in which x represents
which has data and software available for many systems the mole fraction of a component that is being absorbed
and internals designs. from the gas phase by liquid solvent. Usually VN + 1, L0, yN + 1,
x0, and y1 are known whereas LN, V1, and xN are unknown.
13.4 Absorption and Stripping For a multistage unit, the above equations can be written
The design of absorption columns is mainly similar to for any stage (i.e., nth), and through simultaneous solution
those of distillation columns. Absorption columns can be of these two equations a linear equation for the operating
designed as a tray or packed column. However, because line can be obtained. By drawing the operating line and
the gas and liquid flow rates in absorption processes are equilibrium line and using a step-by-step procedure similar
usually less than those for distillation columns, packed to the McCabe-Thiele approach, the number of stages (N)
columns are more common than tray columns. The main can be determined [3]. Analytically and for constant m, this
difference with distillation is that there is no condenser, leads to the Kremser equation for calculation of the number
reflux, and reboiler in the column as shown in Figure 13.15. of theoretical stages N:
In addition, in many practical cases the equilibrium curve
for gas absorption systems is usually a straight line with a y − mx0  1 1
slope of m: yi = mi xi. In cases in which the amount of solute ln  N + 1 1 −  + 
 y1 − mx0  A  A
in the solvent is small and Henry’s law can be applied, mi is N= (13.42)
the same as Henry’s constant (k). However, in general, the ln A
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 323

where A is the absorption factor defined as A = L /mV and absorption, and absorbed components in the liquid phase are
is dimensionless. Because L, V, and m may vary from top stripped by a gas that is usually nonsoluble in the solvent.
to bottom of the column average, A may be calculated as For example, for the case of rich oil (oil with absorbed gases),
A = A1 AN , where A1 = L0 /m1V1 and AN = LN /mNVN + 1. For the best stripping gas is steam, which cannot be absorbed
a single-stage unit, Eqs 13.40 and 13.41 can be solved by oil but it can take some light hydrocarbon gases out of
together, with yN = mi xN through equilibrium relation in oil. A stripping column is best operated at low pressures
which N = 1. and high temperatures (opposite to the conditions in an
Another example of gas absorption units in refinery gas absorption column). When pure steam is used to strip light
plants is to remove heavy hydrocarbons from a hydrocar- hydrocarbon gases out of oil, the number of theoretical
bon gas mixture using a solvent that has a good absorbing stages can be calculated from [5].
power for hydrocarbons. Oils are obviously good solvents
to absorb a hydrocarbon compound from a gas mixture, ni , outlet SiM + 1 − Si
especially if they are from the same hydrocarbon family. In 1− = (13.45)
ni , inlet SiM + 1 − 1
such cases, it is usually desired to remove a certain fraction
of a compound from a gas mixture, which is defined as
in which ni,outlet is the moles of i in the stripped lean oil leav-
recovery, Ei:
ing the stripping column and ni,inlet is the moles of i in the
ni , inlet − ni , outlet rich oil entering the stripper. Si is the stripping factor and
Ei = (13.43) is defined as KiV0/LM + 1. V0 is the moles of stripping medium
ni , inlet entering the column (i.e., moles of steam entering), and LM + 1
is the moles of rich oil entering the stripping column. M is the
where: number of theoretical stages in the column (similar to N for
ni,inlet = number of moles of component i in the gas entering an absorption column). The left side of the above equation
the column, is equivalent to the recovery factor (fraction of i removed
ni,outlet = gas leaving the column, and from rich oil) in the stripper.
ni,inlet – ni,outlet = amount of component i absorbed by the oil A recent article by Binous [16] shows how computer
or removed from the gas. software such as MATLAB and MATHEMATICA can be used
In this definition, it is assumed that the solvent entering to make calculations related to equilibrium-stage separations
the column is free of component i, the absorbing species. and to obtain the number of equilibrium stages for processes
Using definition Ei, Eq 13.43 can be rearranged to be such as distillation, absorption, stripping, and extraction.
written as
13.5 Liquid-Liquid Extraction
AN + 1 − A

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Ei = i N + 1 i (13.44) For liquid systems in which distillation cannot be used to
Ai −1 separate the key component from a liquid mixture because
of low relative volatility, component sensitivity to the high
where Ai is the absorption factor defined in Eq 13.43. In temperatures, or a small amount of solute present in the
finding N (number of theoretical stages) from the above feed, an extraction process using a solvent is an alternative
equation, component i must be a component for which Ai is process. In this process, a solvent (C) is added to a liquid
close to unity and is referred as a key component. mixture (A + B) in which C is mainly insoluble in B and
To recover solvent from the absorption column, the forms two phases (both liquid); however, component A is
lean oil is usually sent to a stripping column as shown the solute and can be dissolved in solvent C. Component A
in Figure 13.16. The stripping process is opposite of gas is the key component that has to be separated from B. The

DRY GAS ABSORBED

MATERIALS
ABSORBER

STRIPPER

RICH GAS

RICH OIL LEAN OIL

Figure 13.16—Absorption and stripping columns in series.

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AST-MNL58-11-0801-013.indd 323 3/12/13 2:24 PM

324 Petroleum Refining and Natural Gas Processing

Feed interface extract

Feed extract

raffinate

raffinate
(a) (b)

Figure 13.17—Schematic of a single-stage extraction unit with two different configurations.

mixture of A and C (overflow) is the extract phase (solvent- equilibrium with each other with a composition known from
rich phase) and the underflow is the raffinate, as shown in ends of the tie-line. The raffinate phase is the ethylbenzene-
Figure 13.17 [3]. In this figure, two different configurations rich phase (higher concentration of B and the lower part of
are shown for an extraction unit in which the feed and the equilibrium curve) whereas the extract phase is solvent
solvent are first mixed and then remain to be separated into rich (higher concentration of C), which is the upper part of
two phases. Separation of A is determined when the two the curve. The point where the length of a tie-line becomes
liquid phases reach equilibrium. The composition of each zero is the plait point. Any mixture with a composition
phase at equilibrium conditions can be determined from outside of the envelope cannot be separated by phase split.
liquid-liquid equilibrium (LLE) calculations or from experi- As in the case of distillation and absorption, design cal-
mental data as discussed in reference 7. Because in each culations involve the number of stages required for a certain
phase there are three components, the composition of each degree of separation and solvent-to-feed ratio. A solvent rate
mixture can be shown on a triangular coordinate system is similar to reflux in distillation, and at the minimum solvent
so that xA + xB + xC = 1. For liquid systems, all compositions rate the number of stages will be infinity. A general schematic
are expressed in terms of weight fraction (wt % /100). The of a multistage extraction unit showing the raffinate and
equilibrium data are presented on a triangular diagram by extract phases is shown in Figure 13.19. The same schematic
a series of tie lines that connect the composition of two also applies to a single-stage unit with N = 1. A multicontact
phases in equilibrium as shown in Figure 13.18. In this extraction unit is usually built as a vertical column similar to
figure, data on the LLE of a ternary system of ethylbenzene- gas absorption columns in which the feed (heavier liquid
styrene-diethylene glycol are presented that can be used to phase) enters from the top and solvent (lighter liquid phase)
separate styrene from ethylbenzene [18]. is introduced from the bottom. The raffinate phase (heavier
For this system, the solvent is diethylene glycol and phase) leaves from the bottom, and the extract (solvent rich)
styrene is to be removed from the ethylbenzene-styrene solu- phase leaves the column from the top. This is to imagine
tion. Any mixture that has a composition in the area inside that the schematic shown in Figure 13.19 is rotated 90º in
of the dashed equilibrium curve splits into two phases in a clockwise direction. The extract phase can be taken in a
distillation column for separation and recovery of solvent.
C Design equations can be developed based on material
1
balance and equilibrium relations. If the weight fraction
0.9 of each component in the extract phase (V phase in Figure
13.18) is shown by y and in the raffinate phase (L phase) is
0.8 shown by x, then the overall material balance and compo-
nent material balances for A and C can be written as
0.7

0.6 L o (feed) + VN + 1 (solvent) = V1 (extract)

(13.46)
+ L N (raffinate) = M
0.5

0.4 x Ao L o (A in feed) + y A, N + 1VN + 1 (A in solvent)

= x A, N L N (A in raffinate) + y A, 1V1 (A in extract) (13.47)
0.3
= M x A,M
0.2
x Co L o (C in feed) + y C, N + 1VN + 1 (C in solvent)
0.1
= x C, N L N (C in raffinate) + y C, 1V1 (C in extract) (13.48)
B 0 A = M x C,M
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
where M is a mixture (with composition of xM) formed by
Figure 13.18—LLE data (in weight fraction) for styrene (A),
ethylbenzene (B), and diethylene glycol (C).
adding the entering feed (Lo) and solvent (VN + 1) streams. By
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 325

Extract VN+1
V2 V3 Vn Vn+12 VN

1 2 n N

Feed L1 L2 Ln-1 Ln LN-1 LN

Raffinate

Figure 13.19—General schematic of a multistage extraction unit.

simultaneous solution of these equations, M, xA,M, and xC,M the minimum solvent required for extraction purposes. This
can be determined as can be demonstrated in the following example.
For the ternary system of acetic acid (A), water (B),
xM = (Lo xo + VN + 1 yN + 1)/M (13.49) and ether (C), the solvent is ether and acid is to be removed
from the aqueous solution. Based on data taken for this
To determine the number of stages, the operating lines can system from reference [3], the LLE envelope is developed
be developed based on the difference between the raffinate as shown in Figure 13.20. Consider 100-kg/h feed of aque-
and extract phase, which remain constant in each cross- ous solution of acetic acid (30 wt %) is being extracted by
sectional area of the extraction column; that is, LN – VN + 1 = the pure solvent isopropyl ether. It is desired to calculate the
Lo – V1 = L1 – V2 = Ln – Vn + 1 = Δ. The difference point Δ can minimum solvent required to have water phase at 2 wt %
be best determined graphically by the intersection of a line acid concentration when it leaves the unit.
connecting LN to VN+1 and a line connecting Lo to V1. The With respect to the symbols used in Figure 13.19, we
number of stages can be determined from a series of operat- have L0 = 100 kg/h, xA0 = 0.3, xC0 = 0, yA,N + 1 = 0, yC,N + 1 = 1.00,
ing lines connecting Δ to L1, L2, etc., and corresponding tie- and xAN = 0.02. The feed is located on the BA coordinate
lines. Likewise, by determining point Δmin, one can determine (Figure 13.20) at xA0 = 0.3. The tie-line passing through this

Δ min

C
1 VN+

0.9

0.8 V1mi

0.7

0.6
M
xCM=0.58
0.5

0.4

0.3

0.2

0.1

B 0 A
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
xAN=0.02
xAM=0.115
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 13.20—Calculation of minimum solvent and number of theoretical stages for LLE.
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326 Petroleum Refining and Natural Gas Processing

point gives V1,min on the envelope, which, if connected to All heat exchangers are governed by the basic energy bal-
point LN (at xA = 0.02), intersects with the line from L0 to VN ance and heat transfer equations, with the differences in the
+1
at point M as shown in Figure 13.20. Reading from the details. The heat transfer in a heat exchanger is described by
figure for this coordinate is xAM,min = 0.115 and xCM,min = 0.58,
and substituting into Eq 13.42 gives VN + 1,min = 160 kg/h. At Q = UoAEff ΔTLMTD (13.50)
this solvent rate, the number of theoretical stages is infin-
ity; however, at a solvent rate greater than this number, xAM The log-mean temperature difference (LMTD) is
is calculated from Eq 13.49 with point M on the figure, in calculated via
which point V1 can be determined from connecting LN to
M and its intersection with the upper portion of the equi- ∆TG − ∆TL
librium curve in Figure 13.20. By connecting L0 to V1 and ∆TLMTD = (13.51)
 ∆T 
its intersection with the LN VN + 1 line, point Δ is determined ln  G 
and can be used to determine the number of ideal units.  ∆TL 

13.6 Heat Transfer Equipment where:

13.6.1 Heat Exchangers ΔTG = greater terminal temperature difference, and
Heat exchangers are used to transfer energy from a hot fluid to ΔTL = lesser terminal temperature difference.
a cold fluid by indirect contact. The hot fluid can be a process Figure 13.21 displays the temperature differences for
fluid, steam, or a heat transfer medium such as hot oil. The countercurrent and co-current exchangers.
cold fluid can be a process fluid, cooling water, sea water, a For the countercurrent exchanger, the terminal tempera-
refrigerant, or a heat transfer medium such as a glycol solution. ture differences are calculated as
Shell and tube exchangers are those in which one fluid
flows through the tubes whereas the other flows through ΔTG = T2 − t1 ΔTL = T1 − t2 (13.52)
a shell around the tubes; heat then transfers through the
metal tube walls. These are the most common exchangers whereas for co-current exchangers they are calculated as
in refinery applications because they can be constructed
to withstand high pressures and temperatures. They also ΔTG = T2 − t2 ΔTL = T1 − t1 (13.53)
provide good heat transfer in most applications.
Plate exchangers are those in which the fluids flow For shell and tube exchangers, which make up most
between layers of corrugated plates. The plates are corru- exchangers in a refinery, flow on either the shell or the
gated to induce turbulence in the fluids, thus increasing heat tube side will be a combination of countercurrent and co-
transfer. Plate exchangers can be either gasketted or welded, current flow. Therefore, it is necessary to correct the pure
depending on the service. Gasketted plate exchangers (com- countercurrent LMTD. Many correction methods have been
monly called plate and frame) are those in which polymer published over the years, including those of Underwood
gaskets are used to isolate the fluids from each other and the [20], Bowman et al. [21], and Maxwell [22]. Wales [23]
external environment. These exchangers can be easily disas- revised the equations of Bowman et al., providing a clearer
sembled for cleaning or maintenance and are often used in relationship.
refinery applications for services involving water or amine. For tubular exchangers, the corrected LMTD replaces
Welded (or brazed) plate exchangers are usually used in the LMTD in Eq 13.50:
very clean services. A block-type plate exchanger can have
multiple process streams, such as those used in liquefied ΔTLMTD = F ⋅ ΔTLMTD (13.54)
natural gas (LNG) liquefaction, NGL recovery, and air separa-
tion facilities. These are not common in refinery applications. The correction factor, F, is calculated via the following
Spiral exchangers are a special type of plate exchanger method. It can also be read from charts published by the
in which the process fluids flow through spiral paths Tubular Exchanger Manufacturers Association (TEMA) [24].
between two plates that have been rolled into such a shape. From reference 21, the hot-fluid-to-cold-fluid temperature
These exchangers are particularly good for services prone change ratio is
to plugging, such as slurries. They are most common in
food-processing facilities, but their use in refineries for T1 − T2
streams such as visbreaker and FCC bottoms products is R= (13.55)
t2 − t1
not unknown and can provide significant benefits [19].
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 13.21—Mean temperature difference.

AST-MNL58-11-0801-013.indd 326 3/12/13 2:24 PM

Chapter 13 n Design Aspects of Separation Units and Processing Equipment 327

Instead of the cold-fluid temperature efficiency used in Wales took this one step further and identified an
reference 21, reference 23 proposed the use of the outlet approximation of Eq 13.57 accurate to 1 % when G ≥ –0.05
temperature gap to inlet temperature gap ratio: (which would mean F < 0.75) and 0.33 < R < 3.00:

T2 − t2  (2.15 + G ) 
G= (13.56) 2.0619 ⋅ ln  
T1 − t1  (1 + 2.15 ⋅ G ) 
F1,2 ≅ (13.64)
 5.5212 + 0.7788 ⋅ G 
Values of G also indicate how much heat exchange is occur- ln  
ring. When G equals +1, there is no heat exchanger possible;  0.7788 + 5.5212 ⋅ G 
when G = –1 there is maximum heat exchange occurring. If
the outlet temperatures are equal, then G = 0. A negative G Equation 13.64 can be combined with Eq 13.63 for approxi-
value indicates a fluid temperature cross. mations of more complex exchanger configurations.
For an exchanger with one shell pass and two tube passes, For most heat exchangers, an F correction factor above
0.8 is desired. The reason is that F can be considered a mea-
 ( R2 + 1)1 2   R+G
sure of the efficiency of the surface area used (and capital
 R − 1  ⋅ ln  1 + GR 
    expended). An F factor below 0.8 indicates that the surface
F1 ,2 = (13.57)
 C + D area is not being put to good use. The curvature of these
ln  equations is such that as G declines, F declines even faster.
 C − D 
This indicates a risk that if you have a heat exchanger with
where C and D are defined as a low F correction factor (i.e., below 0.8), small changes in
process temperatures can result in very little heat transfer
C = (R + 1)(1 + G) (13.58) occurring because of inefficient use of surface area. Plots
of these equations can be found in references 21 and 23 as

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
well as many textbooks on heat transfer.
D = (1 − G ) ( R2 − 1) (13.59)
If the F factor falls below 0.8, it is recommended to
increase the number of shells (or shell passes) to improve
Additionally, for an exchanger with two shell passes and the overall factor. Most commercial process simulators can
four tube passes, calculate the F factor for a heat exchanger (given the number
 ( R2 + 1)1 2  of passes on each side).
 R+G
 2 ( R − 1)  ⋅ ln  1 + GR  It must be noted that the prior method of determin-
  ing the corrected LMTD only applies if the process flows
F2 ,4 = (13.60)
 C + 2 ⋅ ( R + G ) (1 + GR ) + D  are constant, the specific heats of the fluids are relatively
ln   insensitive to temperature, no phase change occurs, and
 C + 2 ⋅ ( R + G ) (1 + GR ) − D  the overall heat transfer coefficient is constant through the
exchanger. If there is a phase change, or the specific heats
Note that Eqs 13.57 and 13.60 are indeterminate for the of the fluids change significantly with temperature, the heat
rare case of R = 1. In this situation, one can replace part of curves will not be straight lines. For such considerations, it
the numerator via is necessary to use a weighted LMTD calculation. Methods
for this have been published, including reference [25].
1  ( R + G )  (1 − G ) The effective surface area, AEff, is the tube surface area
ln  = (13.61)
( R − 1)  (1 + RG )  (1 + G ) that is useful in transferring energy. This means that por-
tions of the tube area that is concealed by the tubesheet
For exchangers with more passes, Bowman et al. [21] pro- are excluded, as is the area of the return bends in a U-tube
vided a generalized form for a given R and number of shell exchanger if the shell side fluid does not actively flow
passes, N. Wales [23] adjusted this in terms of the value G: through the head of the shell (i.e., the shell side fluid around
the return bends is essentially stagnant as is often the case).
The overall heat transfer coefficient, UO, can be deter-
 
N 
 1 + RG1,2  − 1  mined via
  R + G1,2  
GN , 2 N = 1 − (1 + R)   (13.62) 1

 1 + RG1,2 
N
 UO = (13.65)
  − R  1 1 Ao Do  Do  Ao 
 R + G1, 2    h + h A + 2 k ln  D  + RDo + RDi A 
 o i i  i i 

In the rare case of R = 1, the equations are again indeter-

In most applications, the surface areas of each side of the
minate. In this situation,
heat exchanger are the same; therefore Ao/Ai ≈ 1, and the
resistance of the metal tube is very small, leaving the form
G1,2 + 1 − N ⋅ (1 − G1,2 )
GN , 2 N = (13.63) 1
G1,2 + 1 + N ⋅ (1 − G1,2 ) UO = (13.66)
 1 1 
 h + h + RDo + RDi 
 o i 
GN,2N can be substituted into Eq 13.57 to obtain a correction
factor for a three-six, four-eight, five-ten, or six-twelve where the values denoted h are the heat transfer coefficients
exchanger. on the inside and outside of the clean tubes, and the values
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328 Petroleum Refining and Natural Gas Processing

denoted R are the fouling resistances (factors) on the inside When specifying a heat exchanger, the process engineer
and outside of the tubes. Note that in mild fouling services, should also specify the allowable pressure drop for the
the fouling resistance changes the overall coefficient by a heat transfer engineer. The allowable (and eventually the
few percent, and very fouling services can reduce it by a calculated) pressure drops are always specified as “clean”
factor of 10. (i.e., without fouling).
A heat transfer text or exchanger design manual should In Table 13.2, the “Pressure Drop Factor” column
be consulted for more details on how the local heat trans- is a multiplier that should be considered in the design of
fer coefficients are calculated. Typical overall heat transfer hydraulic systems and prime movers, such as pumps and
coefficients (fouled) are shown in Table 13.1. compressors. The factor should be multiplied by the clean
When specifying a heat exchanger, the overall heat pressure drop of the exchanger.
transfer coefficient will be calculated rigorously by the heat When specifying a heat exchanger, the allowable
transfer engineer. For these cases, the process engineer pressure drop should be selected based on the fouling ten-
should provide the fouling factors that the heat transfer dencies and viscosities of the fluids. This is because the heat
engineer should use. Some operating companies or engi- transfer coefficient is dependent on these values. Higher
neering firms have their own data on recommended fouling pressure drops allow for higher fluid velocities, which can
factors. TEMA [24] also publishes recommended design counteract the negative aspects of high viscosity fluids.
fouling factors in their standards. A small excerpt of these Table 13.3 provides some recommended allowable pressure
is provided in Table 13.2. drops based on fluid viscosity.
The pressure drops in Table 13.3 are recommended
because they should provide reasonable fluid velocities in
Table 13.1— Typical Refinery Heat Transfer the exchanger.
Coefficient One alternative to designing heat exchangers with fouling
factors is for the exchangers to be designed using the so-called
Overall “no-foul” design method [26]. This method uses high fluid
Coefficientc,
velocities to reduce the fouling tendencies of the system. This
Hot Fluid Cold Fluid W/m²·K
can be beneficial because the fouling factor for some services
Steam Water 1400–4200 can add significant surface area over the clean requirement.
If one is planning to utilize the no-foul design method, it is
No Phase Change
recommended to add 50–100 % to the allowable pressure
Water Water 900–1700 drops shown in Table 13.3. However, the pressure drop factors
Organic Water 300–900 shown in Table 13.2 for severe fouling services should not be
reduced because predicting fouled pressure drop is still very
Gases Water 30–300 much a guess. For the design and rating of other types of heat
Light hydrocarbonsa Water 300–900 exchangers in refineries, such as plate and spiral exchangers,
the design is usually proprietary and the supplier should be
Heavy hydrocarbonsb Water 100–300 contacted for assistance in rating the performance.
Water Brine 200–500
13.6.2 Air-Cooled Exchangers
Heavy hydrocarbonsb Heavy hydrocarbons 30–300 Air-cooled heat exchangers, often called fin-fan or aerial
Condensing coolers, are very common in many refineries, especially
those where access to raw water for makeup to a cooling
Light hydrocarbonsa Water 500–900
tower or sea water are not readily available. Air-cooled
Organic solvents Water 300–700 exchangers function by having a fan blow atmospheric air
through a bundle of (usually) finned tubes through which
Heavy hydrocarbonsb Water 100–200
the process fluid passes. The configuration is cross flow
at vacuum
because the air flows perpendicular to the process fluid.
Steam, vacuum Water 900–2600 Air-cooled exchanger design is usually performed by the
Ammonia Water 740–1500
engineering contractor or manufacturer.
An evaluation of an air-cooled exchanger can be per-
Vaporization formed using Eq 13.50, with the condition that the terms U
Steam C2–C8 430–1100 and AEff are both on the same basis, either on the bare tube
area (excluding the fins) or on the finned area. The former
Steam Light hydrocarbons a
280–900 is the usual basis. Heat transfer coefficients on a bare tube
Steam Heavy hydrocarbons b
60–500 basis are given in Table 13.4.
To perform a preliminary design of an air cooler, it is
Dowtherm Heavy hydrocarbons b
50–200
necessary to estimate the air-side outlet temperature [27]:
Notes
Light hydrocarbons are defined as materials with normal boiling
( ) −t
a
 T +T
points below 300°C. Heat transfer coefficient is a function of viscosity, (t2 − t1 ) = 8.8 × 10−4 ⋅ U ⋅  2 1 1  (13.67)
and lower viscosities (i.e., lower boiling materials) will generally have  2 
U-values at the higher end of the range given.
b
Heavy hydrocarbons are defined as materials with normal boiling points
above 300°C. The air-side temperature rise, (t2 – t1), is corrected using the
c following:
For heat transfer coefficients in Btu/ft²·h·°F, divide these values by 5.678.--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Copyright ASTM International

AST-MNL58-11-0801-013.indd 328 3/12/13 2:24 PM

Chapter 13 n Design Aspects of Separation Units and Processing Equipment 329

Table 13.2—Recommended Fouling Factors

Fluid Design Fouling Resistance Pressure Drop Factor

h·ft ·°F/Btu
2
m ·K/W
2

Acid gases 0.002 0.00035 1.1

Amine/glycol solutions 0.002 0.00035 1.1

Light hydrocarbon vapors 0.001 0.00018 1.1

Vacuum overhead vapors 0.002 0.00035 1.1

Crude oil (<350°F) 0.002–0.003 0.00035–0.00053 1.2

Crude oil (>350°F) 0.003–0.005 0.00053–0.00088 1.2

Crude oil with salt 0.002–0.007 0.00035–0.00123 1.5

Naphtha 0.002 0.00035 1.1

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Light gas oil 0.003 0.00053 1.1

Heavy gas oil 0.003–0.005 0.00053–0.00088 1.2

Atmospheric residue 0.007 0.00123 1.5

Vacuum residue/visbreaker tar 0.010 0.00176 1.5

FCC light cycle oil 0.002–0.003 0.00035–0.00053 1.1

FCC heavy cycle oil 0.003–0.004 0.00053–0.00070 1.2

Light coker gas oil 0.003–0.004 0.00053–0.00070 1.2

Heavy coker gas oil 0.004–0.005 0.00070–0.00088 1.2

Lubes solvent 0.001 0.00018 1.1

Lubes extract 0.003 0.00053 1.2

Lubes product 0.001 0.00018 1.1

Water, boiler feed 0.0005–0.001 0.00009–0.00018 1.0

Water, condensate 0.0005 0.00009 1.0

Water, cooling tower 0.001–0.002 0.00018–0.00035 1.1

Water, river 0.003 0.00053 1.2

Water, sea 0.0005–0.001 0.00009–0.00018 1.1

Water, silty or hard 0.003–0.005 0.00053–0.00088 1.2

facturers publish correction curves. Generally, air-cooled

Table 13.3—Allowable Pressure Drop exchangers with four or more tube passes are essentially
Allowable ΔP Allowable ΔP countercurrent and the LMTD correction factor can be
Viscosity (mPa·s/cP) (kPa/Shell Side) (kPa/Tube Side) assumed to be 1.0. For fewer tube passes, the curves should
be consulted. Most air coolers are designed for an LMTD
<1.0 35 35–70
correction factor of greater than 0.8. For quick evaluations,
1–5 35–70 70–100 an assumption of 0.9 is reasonable.
5–10 70–100 100–150
13.6.3 Heating Coils
10–25 100–150 150–210 Heating coils are often provided inside tanks where there is
concern about the fluid in the tank becoming very viscous
>25 Heat transfer engineer to recommend
or even freezing if the temperature in the tank were to drop
because of ambient cooling. The heat loss from the tank
is most precisely determined using the method published
(t2 − t1)corrected = (t2 − t1) ⋅ (0.0026) ⋅ (T2 − T1) + 0.886 (13.68) by Kumana and Kothari [28]. This method is somewhat
involved and requires iteration; however, it provides better
This corrected value is then used to determine the LMTD results than other methods. An example set of data is pro-
of the exchanger via Eq 13.51. Similar to shell and tube vided in Figure 13.22.
exchangers, because the flow is not countercurrent, we must Once the heat loss from the tank is determined, one
correct the LMTD using a correction factor. Various manu- can determine the size of the heating method required to
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330 Petroleum Refining and Natural Gas Processing

maintain the tank temperature. There are several methods

Table 13.4—Typical Heat Transfer for heating a tank, including
Coefficients for Air-Cooled Exchangers • A heating coil containing steam or other heating medi-
Hot Fluid Overall Coefficienta, W/m²·K um within the tank,
• An electric immersion heater,
Condensing
• A circulation loop in which the fluid is pumped
Ammonia 550–700 through an external heat exchanger or fired heater and
returned to the tank, and
Refrigerant (i.e., propane) 500–650
• A fire tube inside of the tank where a fuel is combusted
Naphtha 400–600 and the heat of the flue gases heats the tank contents
Diesel/light gas oil 250–300 through the wall of the fire tube.
Electric immersion heaters are best suited to small
Reactor effluent 450–600 heat requirements, and fire tubes are typically only used
Steam 550–900 where other heating media are not available (such as at
remote oil production facilities). In refineries, the most
Gas cooling common options are in-tank heating coils and circulation
Air 50–200 loops through external heaters. The former are best utilized
for lighter materials in which mixing in the tank is provided
Hydrocarbon gases 150–200
by convection resulting from heating or from movements of
Hydrogen 20–100 product in and out of the tank (i.e., diesels and vacuum gas
oils). The latter are best suited to high-viscosity materials
Liquid cooling
in which mixing is not sufficiently provided by convection
Heavy fuel oil 30–100 or oil movements (i.e., atmospheric and vacuum residues).
The sizing of an external heat exchanger is no different
Residue 60–100
than sizing any other heat exchanger in the refinery. This
Vacuum gas oil 60–300 method, with circulation, is the most effective for keeping
Diesel/light gas oil 150–400 large tanks warm, especially for fluids with high viscosities
in which allowing the tank to cool would result in it being
Naphtha 300–500 very difficult to pump out the tank. If the heat duty required
Glycol Solution 550–700 to maintain tank temperature, or to reheat the tank, is
larger than approximately 0.3 MW (106 Btu/h), an external
Water 650–800 heat exchanger is recommended.
Notes Heating coils inside a tank are best used for smaller
a
For heat transfer coefficients in Btu/ft²·h·°F, divide these values by 5.678. tanks with lighter materials (i.e., diesel) or for tanks where
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 13.22—Example curves for heat loss from a tank.

AST-MNL58-11-0801-013.indd 330 3/12/13 2:24 PM

Chapter 13 n Design Aspects of Separation Units and Processing Equipment 331

some water is expected to decant in the bottom of the tank. The Rayleigh number is defined as
The heating coil can then be used to keep the water in the
tank from freezing, or perhaps to keep the diesel from falling gβ CP ρ 2
below the pour point in cold weather. Heating coils inside of RaD = GrD Pr = (Tw − T∞ ) D3 (13.75)
µk
tanks are usually heated with steam, although hot oil can and
should be used if the fluid in the tank is to be stored at temper- For Eqs 13.71 and 13.74, the properties of the fluid should
atures above 95°C. This is because a steam coil can leak water be determined at the wall temperature of the tube. For
into the tank contents and, if the temperature were to rise tubes heated with steam, it can be safely assumed that this
above 100°C, a boil-over event could occur in which the water is essentially the temperature of the steam.
flashes and pushes hydrocarbon over the top of the tank. For most tank coils, the overall heat transfer coefficient
The heating coil can be sized using a typical heat transfer determined will range from 4.0 W/m²·K (free convection) to
equation for cylinders. The overall heat transfer from the 24 W/m²·K (forced convection) (0.7 – 4.3 Btu/h·ft²·°F). The
coil to the tank is described by internal heat transfer coefficient can be estimated for steam
and liquid heat transfer fluids; however, for steam it is
Q = Uo Acoil(TS − T∞) (13.69) almost unnecessary because it will be orders of magnitude
better than for the outside coefficient.
where: For condensing steam, where the velocities are low
Th = average temperature of the heating medium, and (Re < 35,000), Chato [31] recommends
T∞ = bulk temperature in the tank.
The overall heat transfer coefficient, Uo, is determined via 14
 gρ (ρ − ρ v ) kl3 ∆H f′ 
−1
hD = 0.555 ⋅  l l  (13.76)
1 1 tm 1   µ l (Tsat − Tw ) D 
Uo =  + + +  (13.70)
 ho hf km hi 
where ΔHf′ is the modified latent heat of the steam:
If the heating medium is steam, then the external resis-
tance is orders of magnitude greater than the internal or 3
∆Hf′ = ∆H f + CP , l (Tsat − Tw ) (13.77)
wall resistance, and even the fouling term is negligible. 8
In this case, just the external coefficient is required and
U o = h o. The wall temperature, Tw, must be determined via iteration.
If jet-mixers are provided along the walls of the tank, For a liquid heat transfer fluid, the Dittus-Boelter equa-
then the heat transfer becomes forced convection, and the tion [32] can be used over a narrow range of conditions:
equation of Churchill and Bernstein [29] can be used:
NuD = 0.023 ReD0.8 Pr n
  
58 45
n = 0.3 for cooling of the tubesiide fluid
0.62 ⋅ Re1D2 Pr1 3   ReD (13.78)
NuD = 0.3 + ⋅ 1 +    (13.71) 0.7 ≤ Pr ≤ 160
[1 + (0.4 Pr )2 3 ]1 4   2.82 × 105  
ReD > 10 4
where the average Nusselt number is defined by
This equation can have errors as large as 25 % [33]; there-
hD fore, caution is recommended. More recent correlations by
NuD = (13.72) Petukhov [34] and Gnielinski [35] can be used over wider
k
ranges of Reynolds number with higher accuracy, but they
require estimation of a friction factor inside of the pipe.
and the Prandtl number is defined by
13.6.4 Fired Heaters
CP k
Pr = (13.73) Fired heaters, or furnaces, are used in refining applications
µ in which the heat input required is too large to be economical

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
with steam or hot oil heat (i.e., many exchanger shells,
The area of the coil used in Eq 13.69 should be limited plus large boilers) or in which the heat input temperature
to those portions that experience fluid velocities above is higher than is feasible with steam or hot oil. This section
0.3 m/s (1 ft/s), below which free convection is essentially deals with process fired heaters and does not discuss boilers
occurring. or heat-recovery steam generators.
If there are no jet mixers, then one relies on free convec- This section defines what fired heaters are and why
tion in the tank fluid. This is very ineffective at transferring they are used. It also explains how to perform simple
any significant heat to the tank, but it can still be sufficient performance calculations for a fired heater. The detailed
to prevent water from freezing. For free convection from a design of fired heaters is beyond the scope of this text.
coil, the correlation of Churchill and Chu [30] can be used:
13.6.4.1 Introduction
 
2 In many refineries, steam pressures greater than 4500
 0.387 Ra1D6  kPag/650 psig (saturation temperature 260°C/500°F) are
NuD = 0.6 +  (13.74)
 9 16 8 27 often unavailable. In addition, one should remember that
 1 + (0.559 / Pr )  
higher pressure reduces the latent heat of water, requiring

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AST-MNL58-11-0801-013.indd 331 3/12/13 2:24 PM

332 Petroleum Refining and Natural Gas Processing

larger flows to obtain a given heat flow. At 334°C (650°F), leaving the radiant zone. This section usually recovers
the latent heat is half that at 300 kPag (44 psig), and at approximately 10–30 % of the heat released by combustion.
374°C (705°F) the latent heat of steam is zero. Also, note The air preheater is an optional part of the heater that can
that a saturation steam temperature of 334°C occurs at be used to recover low-grade heat from the flue gas to preheat
13,500 kPa (1960 psig). the combustion air. This is usually economical on heaters
Hot oils can be used to obtain high temperatures at larger than 10 MW (30 MMBtu/h), but it is dependent on fuel
lower pressures than are required for steam. Dow’s Syl- value and current market capital costs. This can increase the
therm® 800 offers a maximum supply temperature of 400°C overall efficiency of the furnace to approximately 90 %.
(750°F), but this is a liquid phase (sensible heat) medium. The selective nitrogen reduction section is an optional
Dowtherm® A and Solutia’s Therminol® VP-1 offer maxi- part of the heater that may be required if limitations on
mum operating temperatures of 400°C (750°F) in vapor oxides of nitrogen (NOx) emissions require it. This is briefly
phase operation, but the latent heat is only approximately described later.
200 kJ/kg (86 Btu/lb). Using sensible heat or low latent heat Flue gas cleanup or capture absorbers are uncommon,
fluids will require very large flows to obtain large duties. but they can be required to capture sulfur dioxide (SO2) or
Therefore, such heat-transfer fluids are usually restricted to carbon dioxide (CO2) from the flue gas. The process tubes
smaller heating requirements. are the tubes that contain the process fluid(s) inside of the
Fired heaters are generally of a design as shown in furnace and are exposed to the radiant or convective sections.
Figure 13.23 and are usually designed to API Standard 560, Process tubes are usually bare tubes, but extended-surface
which is also numbered as ISO 13705. Older furnaces and tubes (e.g. fins) are sometimes used in convection sections
those in regions that did not historically use API standards to obtain higher heat transfer rates.
may not be designed in complete accordance with the standard, A return bend or header is a piece of tubing that is
but the same methods can be used to evaluate performance. bent to 180°, or is cast or forged, to connect two tubes in
The parts of the fired heater shown above are described the furnaces. The burners introduce the fuel and air mixture
below. to the firebox, where the fuel is ignited. Burners can range
The radiant section or firebox is that part of the heater from simple gaseous fuel nozzles to complex devices that
where the process tubes are heated primarily by radiation utilize recycled flue gas for NOx reduction, atomize liquid
from the flame in the furnace. In most fired heaters, 50–70 % fuels, or handle particulate solid fuels.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

of the heat released by combustion of the fuel is recovered The pilots are small burners, usually operated on an inde-
in the radiant section. pendent fuel supply, which provide the ignition energy for the
The convection section is the part of the heater where main burners. Sootblowers are devices used to inject steam
process tubes are heated by convection from the hot gas or air into the furnace to clean soot from the heat transfer

FLUE GAS FLOW

CONVECTION
SECTION
PROCESS FLUID BIRDSCREEN
COLD INLET

STEAM OR OTHER
HEATING MEDIUM

SHIELD TUBES

STACK

FORCED DRAFT FAN

RETURN BEND
BRIDGEWALL

RADIANT RADIANT
SECTION SECTION

SELECTIVE CATALYTIC AIR PREHEATER

REDUCTION SECTION

PILOTS
PROCESS FLUID BURNERS
HOT OUTLET INDUCED DRAFT FAN
AMMONIA

ATOMIZING
COMBUSTION AIR
STEAM
FUEL TO MAIN
BURNERS
NATURAL GAS
TO PILOTS

Figure 13.23—Schematic of a refinery fired heater.

AST-MNL58-11-0801-013.indd 332 3/12/13 2:24 PM

Chapter 13 n Design Aspects of Separation Units and Processing Equipment 333

surfaces. These are only required on furnaces burning liquid • Catalytic reforming charge furnaces,
or solid fuels. The casing is the metal covering of the furnace. • Thermal oil heaters (for indirect heat transfer loop),
The forced- or induced-draft fans provide the motive • Steam superheaters (for superheating steam generated
force to create a pressure profile through the furnace. These in by the process), and
are not necessarily required and depend on the size and • Steam-hydrocarbon reformer furnaces (for hydrogen
complexity of the furnace. Such fans are common for large or synthesis gas production).
furnaces with air preheaters, selective nitrogen reduction Charge furnaces for crude and vacuum distillation
systems, or flue gas capture systems. A furnace with both units are complex units because the feed is vaporizing at
fans is called a balanced-draft furnace whereas one with no high temperatures. Outlet temperatures greater than 360°C
fans is called a natural-draft furnace. (680°F) for atmospheric and 400°C (750°F) for vacuum
The stack provides two key functions for the furnace. distillation furnaces are not advised because undesirable
The first is to provide draft, or the induced-pressure profile cracking reactions and coking/fouling of the tubes are likely
of the furnace (for furnaces without fans). Because the hot at such conditions. Mass fluxes of the process fluid should
flue gas has greater buoyancy than the cooler atmosphere, be kept high to prevent fouling. The high pressure drop and
the pressure at the bottom of a stack is lower than that at low outlet pressures, particularly in vacuum service, result
the top of the stack (i.e., atmospheric pressure). This pressure in the tube passes increasing in size through the furnace
profile (from atmospheric pressure to the lower pressure at because of the increase in volumetric flow. In a new design
stack bottom) is called draft. The second function of the or evaluation, it is critical to check the velocities throughout
stack is to disperse the flue gas into the atmosphere. The the tube passes to ensure that low velocities do not occur

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
exit temperature, velocity, and elevation of the stack top all (i.e., tube size increases early). These furnaces often have
affect how the flue gas is dispersed and what the concentra- velocity steam injected with the feed to provide additional
tion of contaminants in the flue gas (i.e., oxides of sulfur volume, increasing the fluid velocities in the tubes. To avoid
[SOx] and NOx) is at grade around the facility. coking problems, average heat fluxes should not exceed
35 kW/m². For furnaces processing very refractory feedstocks
13.6.4.2 Configurations (e.g., Athabasca), lower values are recommended.
Vertical (or helical) cylindrical heaters are generally used These furnaces are usually cabin-type heaters (because
for small duties under 10 MW (34 MMBtu/h). These are tall of the scale) and can have the tubes vertically or horizontally
cylinders with a single row of vertical tubes against the wall oriented. Vertical tube orientation in vacuum furnaces is
of the cylinder. A single burner or small pattern of burners not desirable [36] because it forces the process fluid to pass
is located on the floor of the furnace. In some designs, the through the highest flux zone multiple times, increasing
tubes are oriented in a helix rather than a bank of vertical the chances of coking. The control of the feed to each tube
tubes. For cylindrical furnaces, the flow to the individual pass is critical in these furnaces because the pressure drop
tube passes is usually not controlled. These furnaces are per pass can vary because of varied fouling or heat fluxes.
often natural draft and do not have air preheaters, and Delayed coking and visbreaking charge heaters are very
sometimes they do not have even have convection sections. specialized designs because the process temperatures are
However, if fuel prices are high, convection sections and often greater than 480°C (900°F) because the intention is to
air preheat on small furnaces may become more common. crack the feedstock. These furnaces are often designed for
Cabin (or box) heaters are used for larger duties. For steam or air spalling and even pigging. In a large delayed
very large duties (>30 MW), a multiple cabin heater will likely coker unit, the furnace may have eight or more cells so that
be selected for constructability and process control reasons. a cell can be taken offline and pigged while the unit is in
In these furnaces, the process tubes run either vertically or operation. This spalling or pigging is required because of
horizontally along the walls of the firebox, and sometimes the buildup of coke and other scale (because of minerals
they run between the rows of burners (double-fired tubes). in the feed) on the tubes. For the design or evaluation of
The burners are either on the floor of the furnace or on the a delayed coker furnace, it is recommended to contact the
walls. This is the type of furnace depicted in Figure 13.23. technology licensor. The control of the feed to each tube
The selection of vertical or horizontal tubes is dependent on pass is critical in these furnaces because the pressure drop
the process requirements. Double-fired tubes are used when per pass can vary because of varied fouling or heat fluxes.
it is desired to keep heat fluxes low. Because these furnaces Hydrotreater charge furnaces are generally less severe
are large, the feed is usually split into multiple tube passes than other furnace applications, except in the case of resi-
in the radiant section. The choice to independently control due hydrocrackers in which temperatures are high and the
each pass is usually up to the preference of the owner and feedstock will tend to crack. These furnaces can range in
operator. However, as discussed below, there are good reasons size from small cylindrical furnaces to very large cabin
to independently control each pass in some services. types. Average radiant heat fluxes can range from 30 to 40
kW/m² (lower for heavier materials and higher for naphtha).
13.6.4.3 Applications of Fired Heaters For naphtha and kerosene hydrotreaters, a key param-
Fired heaters are often used for the following applications eter that must be considered is that the feed to the furnace
in a refinery: should be 100 % vapor phase. Having a two-phase feed
• Atmospheric and vacuum distillation charge furnaces, to the furnace with a 100 % vapor outlet means that some-
• Delayed coking charge furnaces, where in the furnace tubes there will be a dry point where
• Visbreaker charge furnaces, the last liquid evaporates. At this point in the furnace, the
• Hydrotreater/hydrocracker feed furnaces, tube metal temperature profile will have a step increase,
• Hydrocracker hydrogen heaters, resulting in very high stresses in the tube. This can result in
• Hydrotreater/hydrocracker fractionation charge furnaces, catastrophic tube failures and should therefore be avoided.
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334 Petroleum Refining and Natural Gas Processing

The control of the feed to the individual passes of This is feasible for liquid and solid fuels in which the
the furnace is up to the licensor and owner. For a verti- atomic composition of the fuel is known. In such cases,
cal tube furnace, individual pass control is recommended. the fuel composition is usually known on a mass basis
If the individual passes are not controlled, symmetrical and must be converted to molar. For the purposes of
piping on the inlet and outlet of the furnace is critical. If combustion calculations, it is safe to assume that sulfur
the furnace is single phase (i.e., naphtha), individual pass and nitrogen oxidize to the forms shown here because
control is not warranted. they are small portions of the overall heat of combustion
Hydrogen heaters are usually only found in high-severity (some of the nitrogen in the fuel will actually reduce to N2).
hydrocrackers. These units are fairly simple, except that The nitrogen content of the fuel can simply be ignored in
process temperatures can reach 538°C (1000°F) with very most cases because it has minimal effect on the flue gas
high hydrogen partial pressures. Additionally, because the composition.
heat transfer coefficient on the process side is low, the tube For gaseous fuels, one usually knows the composition
metal temperatures can be very high. All of this requires on a molecular basis, such as hydrogen, methane, propane,
special metallurgies (e.g., 347H Stainless) and careful etc. For such fuels, it is easier to use the stoichiometry per
monitoring of tube metal temperatures. component. Here, methane is shown as an example:
Hydrotreater and hydrocracker fractionation furnaces
are less severe than crude distillation furnaces, except in CH4 + 2 ⋅ O2 → CO2 + 2 ⋅ H2O (13.80)
the case of residue hydrocrackers. These furnaces can be of
whichever configuration is the most economic, although hori-
zontal cabin types are recommended. Average radiant tube For each reaction, the heat of combustion is known, allowing
fluxes can be from 38 to 50 kW/m². For units producing diesel, the total heat of combustion to be calculated:
lower fluxes and lower tube wall temperatures may be desired
because temperatures above 360°C (680°F) have been known ∆HLHV = ∑ xi ∆HLHV,i (13.81)
to result in cracking and undesirable color in the product. i

Catalytic reforming furnaces heat the feed to the

endothermic reforming reactor. Such furnaces are often where i is the fraction of a given component in the fuel.
designed similarly to naphtha hydrotreater furnaces and Using this stoichiometry and heats of combustion, we
are usually vertical cylindrical type. can determine the composition of the flue gas and the heat
Thermal oil furnaces are usually vertical cylindrical release of the combustion. A selection of heat of combustion
units, sometimes with convection boxes. The heat fluxes data is provided in Table 13.5.
and tube wall temperature requirements are specific to The heating value of fuel oils can be estimated using
the thermal oil used. These data are readily available the following correlation, which was curve-fitted from data
from the thermal oil suppliers (e.g., Dow Chemical, Solutia). in Chapter 27 of reference 6.
If the thermal oil is being vaporized, then individual pass
control should be considered (unless it is a thermosyphon-
type vaporizer with a drum). Table 13.5—Heat of Combustion Data for
Steam superheaters are mostly vertical cylindrical Selected Fuels
units, usually without convection boxes. The heat fluxes are Lower Heating Value
similar to those of boilers. Because the process-side heat Fuel (MJ/kg)
transfer coefficient is low, the tube metal temperatures can
be high, requiring special metallurgy. Hydrogen 121
Hydrogen reformers are very specialized units that Carbon monoxide 10.9
can be fired from the top, side, or bottom, and can have
Methane 50.0
vertical or horizontal tubes.
Ethane 47.8
13.6.4.4 Combustion Calculations Propane 46.4
Combustion calculations provide key information about a
Butanes 45.8
fired heater design. The first is to determine how much air
is required to burn the fuel, and the second is to determine Gasoline 44.4
the energy available in the flue gas. Kerosene/jet fuel 43.0
There are two ways to perform combustion calculations.
The first is using traditional combustion equations using the Diesel 43.0
stoichiometry of the combustion reactions and the heats of Heavy (No. 6) fuel oil 38.0
combustion. An adiabatic flame temperature calculation can
be used to determine the theoretical flame temperature. Petroleum coke (dry basis) 36.0
The stoichiometry of combustion can be shown as Anthracite coal 35.0

Bituminous coal 26–32

 y z
C x H yO zS w N v +  x + w + v + −  ⋅ O2 → Subbituminous coal (range of volatiles) 14–21
 4 2
y Lignite (range of water contents) 5–10
x ⋅ CO2 + ⋅ H 2O + w ⋅ SO2 + v ⋅ NO (13.79)
2 Peat, wet 2.5
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AST-MNL58-11-0801-013.indd 334 3/12/13 2:24 PM

Chapter 13 n Design Aspects of Separation Units and Processing Equipment 335

∆HLHV = − 12.649 ⋅ SG 2 + 9.3575 ⋅ SG − 0.275 ⋅ TF, which is iterative, because of the dependence of the heat
(13.82) capacities, CP,k, on temperature.
( wt % S ) ⋅ SG −0.75 + 43.9893 A commercial simulator makes these calculations much
easier than doing so manually because integrating the
This equation provides lower heating values (LHVs) in specific heat functions can be quite involved. The reader is
megajoules per kilogram. Conversion to British thermal advised to review a thermodynamics text for more on this
units per pound is obtained by multiplying the result calculation [37].
by 429.9. A second method of performing a combustion calcu-
The heating value of a gaseous fuel can be estimated lation is possible for fuels when the exact composition is
from molecular weight if the composition is not available: known (i.e. gases), using a commercial simulator. Combustion
is a free-energy minimization reaction, or at least very close
ΔHLHV = 5.775 + 1.829 ⋅ MW (13.83) to reaching the minimum free energy of the system. Most
commercial simulators have a unit operation called a Gibbs
This equation provides LHVs in megajoules per Newton- reactor (or something similar) that performs a free-energy
cubic metre and should be considered accurate to ±1.5 minimization calculation by changing the composition of the
MJ/Nm³ for gases with molecular weights below 44.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
stream. By inputting all of the reactants and allowing all of
It is important to account for the inert and excess species the possible combustion products, a Gibbs reactor can accu-
in the combustion air and fuel, such as nitrogen (N2), argon rately estimate the flue gas composition and the theoretical
(Ar), water (H2O), excess oxygen (O2), and carbon dioxide flame temperature (if you make the reactor adiabatic). This
(CO2). The last may be present in the fuel at a concentration method is usually faster, but it should be used with care. The
that is significant (~2 %). The quantity of water vapor present tolerances of the simulators can result in small percentages of
in the combustion air can be determined using a psychro- unburned fuel (usually hydrogen) and higher than real levels of
metric chart or simulator. The composition of dry air is CO (if it is allowed in the model). It is also not recommended
approximately 78.08 % N2, 20.95 % O2, 0.93 % Ar, and 0.04 to include species such as nitric oxide (NO), nitrogen dioxide
% CO2 (molar basis). The water content in atmospheric air can (NO2), and sulfur trioxide (SO3) because these reactions are
be significant (6.4 vol % at 100 % relative humidity at 100°F). kinetically limited and will not go to a free-energy minimum.
Excess oxygen is provided as excess air. Most furnaces Once the theoretical flame temperature and composition
are designed for 10–30 % excess air, with the lower end of the flue gas are known, the calculation of the heat available
used for gas-fired balanced draft furnaces and the higher through the radiant and convective sections of the furnace
end for oil-fired natural draft furnaces. The purpose of can be determined by calculating the enthalpy available
excess air is to ensure that combustion is complete, leav- between the flame temperature and the bridgewall tempera-
ing only parts-per-million levels of CO and hydrocarbons ture (i.e., exit of the radiant section) and then down to the
remaining. Furnaces operating with sufficient excess air gas flue temperature leaving the convection section. This is
should have at least 2 mol % O2 remaining in the flue gas. again most easily accomplished with a commercial simulator.
One aspect that is often overlooked is that the heats For a well-designed furnace, the bridgewall temperature
of combustion available in the literature are generally at should be between 800°C and 1000°C for most services [38].
a standard temperature (To)—either 298 K (25°C / 77°F) in The design or rating of the radiant heat transfer
scientific literature or 60°F (15.56°C/288.7 K) in engineering requires a more detailed analysis than this text can provide.
literature. The heat of combustion values should be net, or The reader is advised to review the publications by Lobo
LHVs, in which the latent heat of the water in the flue gas and Evans [39], Cross [40], Mekler and Fairall [41], and the
is not included. To determine the flame temperature, we Heater Design website [42] for more of the detailed heat
must consider the enthalpy present in the combustion air transfer calculations. The four-part dissertation by Berman
and fuel as well as the heat of combustion: [43–46] is also recommended for a complete review of
TIN furnace design considerations.
∆HT = ∑ mi ∫C P ,i
(T ) dT + ∑ m ∆H
j LHV , j
(13.84)
i T j 13.6.4.5 Efficiency
A key parameter of fired heater design and evaluation is the
where the ΔHT term is the total enthalpy change from the efficiency of the furnace. There are two efficiencies often ref-
inlet air and fuel conditions to the flame. The summation erenced with regard to furnaces: (1) fuel efficiency, which
subscript i indicates all of the species present in the fuel and considers only that energy present in the fuel (ΔHLHV),
combustion air, including inerts. The subscript j indicates excluding any energy input (or shortage) from the ambient air
the reactants in the combustion. (if ambient is different than 60°F) or an atomizing medium
Determining the theoretical flame temperature means such as steam, and (2) thermal efficiency, which consid-
that we must assume that the combustion is adiabatic (i.e., ers all energy inputs. The thermal efficiency is shown here
no heat losses): (from reference 47):
T
∆HLHV + Ha + H f + Hm − (Qr + Qs )
0 = ∆HT − ∑ mk ∫ CP ,k (T ) dT (13.85) η= (13.86)
TF
∆HLHV + Ha + H f + Hm

where the appropriate thermodynamic model is used to where:

calculate the specific heat of each component of the flue gas. Ha = enthalpy correction of the combustion air,
The subscript k indicates all of the species present in the Hf = enthalpy correction of the fuel, and
flue gas, including inerts. This equation must be solved for Hm = enthalpy correction of the atomizing medium.
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336 Petroleum Refining and Natural Gas Processing

Each value is usually expressed in terms of energy per The problem of course is to predict the concentration
mass of fuel (MJ/kg fuel, Btu/lb fuel). Alternatively, the of SO3 in the flue gas. Oxidation of SO2 to SO3 is not well
calculation can be done on total energy flow (i.e., GJ/h, understood. The activation energy required is high, but it is
MMBtu/h) for the furnace. influenced by several factors, such as excess oxygen, flame
The values Qr and Qs are the heat losses due to radia- temperatures, and the presence of catalytic metals in the
tion to the environment and the heat losses in the stack flame, such as nickel or vanadium from the fuel. Various
gas, respectively. The heat losses due to radiation for a sources [50,51] indicate that measured levels of SO3 in flue
furnace will usually be between 1 % and 4 %, with the gas range from 0.1 % to 3 % of the SO2 concentration. Design
low end of the range on furnaces that have better casing guidelines at some engineering firms and boiler manufactur-
insulation. The stack losses are directly related to the stack ers assume 5 % for design purposes. Additionally, in the design
temperature. of a fired heater, it is recommended that the flue gas tempera-
The stack losses should be determined via the following ture always should exceed the predicted acid dewpoint tem-
equation: perature by at least 25°C (45°F) to account for uncertainties.
A warning for furnaces in cold climates: An uninsu-
T
1 lated stack can result in low stack wall temperatures.
Qs =
mf
∑ mk ∫ CP ,k (T ) dT
k
(13.87) For one furnace the author assessed, the stack gas exit
Ts
temperature was 115°C, and the predicted acid and clean

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
water dewpoints were 93°C and 45°C, respectively. With
There are two choices for performing this calculation. A an ambient temperature of –40°C and a wind, the stack wall
process simulator can be used to determine the heat avail- metal temperature fell to just 32°C. In this case, operators
able in the flue gas (from stack temperature to reference continuously drained acidic water from the stack bottom.
temperature). This is done by modeling a cooler on the flue If the stack metal temperature is expected to fall below
gas with the outlet conditions set at 60°F (15.556°C) and a the dewpoint, then an acid-resistant lining (polymer or
vapor fraction of 1.0. This is necessary to avoid condens- ceramic) is recommended.
ing the water in the flue gas. The simulator will predict a
pressure much below atmospheric, but this is acceptable
13.6.4.7 Selective Nitrogen Reduction
because the heat energy is not very pressure dependent.
As environmental regulations are tightened around the
The second choice is to follow a tabular method, as is pre-
world, the implementation of selective nitrogen reduction to
sented in Appendix G of reference [47] or as presented in ref-
obtain very low NOx emissions is becoming more common.
erence [48]. Both references provide an example calculation.
In many jurisdictions, NOx limits can be achieved using
Using an air preheater, it is possible to achieve thermal
low-NOx or ultra-low-NOx burners; however, the strictest
efficiencies in excess of 92 % in a modern furnace. The limi-
rules require greater effort.
tation on furnace efficiency is usually due to the minimum
Selective noncatalytic reduction (SNCR) is generally
stack temperature acceptable to avoid sulfuric acid (H2SO4)
performed at a flue gas temperature between 870°C and
deposition.
1150°C (bridgewall temperature). Urea or ammonia is
injected into the flue gas at this point, whereby the ammonia
13.6.4.6 Acid DewpoinT reacts with NOx to form molecular nitrogen, N2. Although in
The minimum stack temperature when burning clean fuels,
theory this can achieve up to 90 % reduction in NOx, prob-
containing no sulfur, is limited simply by the dewpoint of
lems of mixing, residence time, and temperature gradients
the water vapor in the stack. This water vapor condensing
mean that performance is usually limited to 30–40 %.
can result in corrosion because dissolved O2 and CO2 can
Selective catalytic reduction (SCR) is generally per-
attack economizer tubes, air preheaters, and the stack itself.
formed inside of or after the convection section. It requires
However, few fuels contain no sulfur.
a flue gas temperature of 230–450°C (450–840°F), with
Combustion of fuels containing sulfur result in SO2.
temperatures below 360°C (680°F) requiring longer resi-
SO2 can dissolve in condensed water, but it is a weak acid
dence times in the catalyst bed. The catalyst is a ceramic
and does not significantly affect the dewpoint in the stack.
(often TiO2) support, with an active catalytic layer that
However, a small portion of the sulfur in the fuel will oxi-
can be a base metal oxide (i.e., vanadium or tungsten),
dize to SO3, which is highly hygroscopic and condenses as
a zeolite, or a precious metal (i.e., platinum group). The
H2SO4 at temperatures above that of water. Hot H2SO4 is
base metal oxide catalysts are the least expensive, but they
corrosive to almost all metals (Ta and Pt excepted). Oper-
have the problem of catalyzing the oxidation of SO2 to SO3.
ating a furnace below the dewpoint of H2SO4 will quickly
Zeolites have a wider range of temperature stability with
destroy economizer tubes, air preheaters, dampers, and
reduced catalytic activity for SOx. Platinum-group metals
even the stack walls.
are of course very expensive. The catalyst is usually of a
The dewpoint of H2SO4 can be predicted using the
honeycomb or plate configuration, with the former provid-
correlation developed by ZareNezhad [49]:
ing smaller units but with higher pressure drop and higher
fouling potential.
TDP = 150 + 11.664 ⋅ ln ( PSO3 ) + 8.1328 ⋅ ln ( PH2O ) − Other problems with SCR include the potential for-
(13.88) mation of ammonium sulfate in fuels with high sulfur
0.383226 ⋅ ln ( PSO3 ) ⋅ ln ( PH2O )
contents, which can precipitate and plug the SCR and the
air preheater. Another problem with coal, coke, and heavy
where TDP is the dewpoint in degrees Celsius and the partial fuel oil-fired furnaces can be the presence of arsenic oxide
pressures of water and SO3 are expressed in millimetres of (As2O3) in the flue gas. This gaseous form of arsenic will
mercury. poison the SCR catalyst.
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 337

13.7 Two- and Three-Phase Separators If the terminal velocity is higher than the superficial velocity
Two- and three-phase separators are a key part of any oil proof the continuous phase, then the particle will fall (or rise)
duction, upgrading, refining, or chemical synthesis process. against the continuous phase motion. If not, then it will be

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
This section discusses the design of gravity separators used carried with the continuous phase.
to separate gas-liquid, liquid-liquid, and gas-liquid-liquid Many published methods for sizing separators use the
separators. Solids separation is not discussed. A typical Souders-Brown equation, which uses the empirical factor K
example in refining applications is the separation of gas, to relate the allowable superficial velocity of the continuous
hydrocarbon liquid (oil), and water. phase to the difference in fluid densities:
Separators may be oriented in either the horizontal or
vertical; the latter is generally only applicable where the ρP − ρC
ua = K (13.95)
quantity of liquids is small (<10 % by mass) compared with ρC
the vapor phase, or where plot space limitations are a factor.
Separator vessels are generally sized based on the dis-
Separation device vendors often have values of K available
engagement of the phases, with the hold-up volume (time)
for their specific equipment, but a typical published source
being secondary. However, the hold-up time, particularly
is available in the Gas Processors and Suppliers Association
in high liquid rate applications, can govern the sizing of a
(GPSA) Engineering Databook. Table 13.7 is taken from
vessel. This will also be considered herein.
this source:

13.7.1 Disengagement Theory

Separator calculations are based on determining the veloc- Table 13.7—GPSA K Values
ity of particles of a dispersed phase from the forces exerted
on said particles rising or falling through a continuous phase. Separator Type Pressure (psig) K Factor (ft/s)
Three forces act on a particle moving in a fluid: gravity, Horizontal with vertical pad 0.40–0.50
drag, and buoyancy. The derivation of these equations has
Vertical with horizontal pad Atmospheric 0.35
been shown elsewhere and need not be repeated here. Solv-
ing these equations for the particle velocity results in the 300 0.33
following:
600 0.30

4 ⋅ gDP (ρ P − ρ C ) 900 0.27

uT = (13.89)
3 ⋅ CD ρ C 1500 0.21

Vacuum 0.20
The actual settling velocity depends on the drag coefficient
Notes:
(CD), which is dependent on the Reynolds number of the
K = 0.35 at 100 psig; subtract 0.01 for every 100 psi above 100 psig.
particle as it moves through the fluid. For glycol or amine solutions, multiply the above K values by 0.6–0.8.
Typically use one half of the above K values for approximate sizing of
ρ C DP uT vertical separators without mist eliminators. For compressor suction
Re = (13.90) scrubbers and expander inlet separators, multiply K by 0.7–0.8.
µC

The relationship between the drag coefficient and Reynolds

The K value can be related to the particle size and drag
number is shown by three equations [6], depending on the
coefficient by setting the Souders-Brown allowable velocity
Reynolds number:
equal to the terminal velocity determined in Eq 13.89:

4 ⋅ gDP
Table 13.6—Settling Regime K= (13.96)
3 ⋅ CD
Newton’s Re > 1000 CD = 0.44 (13.91)
regime This allows one to use the K-value method for sizing of a
separator and then checking the minimum particle size
Intermediate 1 < Re < 1000  24 
regime ( )
C D =   ⋅ 1 + 0.14 ⋅ Re0.7 (13.92)
 Re 
that would disengage in the given dimensions (or vice
versa).
Stokes’ Re < 1 24
regime
CD = (13.93) 13.7.2 General Assumptions and
Re
Clarifications
In general, the equations provided for disengagement are
based on a dilute suspension of small, rigid, spherical parti-
The terminal velocity of the falling (or rising) particle is
cles falling (or rising) through a stagnant Newtonian medium.
calculated and then compared with the superficial velocity
There are several situations in which this is not the case.
of the continuous phase.
If the continuous phase is non-Newtonian (i.e., vis-
cosity is shear-dependent), then the reader is directed to
QC Perry’s Handbook [6] for guidance on such separations.
uS = (13.94)
AX If the particle sizes are very small (< 0.5 micron), then

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AST-MNL58-11-0801-013.indd 337 3/12/13 2:24 PM

338 Petroleum Refining and Natural Gas Processing

Brownian motion can control the separation because the

particles are influenced by individual molecule motion, Table 13.8—Typical Hold-Up Times for
which can overcome the force of gravity. If the particles Separators
(droplets/bubbles) are large enough to become distorted Hold-Up
from spherical, then this will change the drag equations. Service Time (min)
Distortion from spherical is probable if the Eötvös number
Uncontrolled feed to units
(NEO) falls below 0.4:
Wide variation in operations, batch operations. 30–300
gDP ⋅ ρ P − ρ C Minor variation in operations, predictable 20–30
NEO = (13.97) variability
σ
Controlled feed from other process units
where σ is the interfacial tension between the phases.
Upstream unit has poor control (yield variation) 15
If the particles are likely to be nonspherical, then the
correlations of Clift [52] or Hu and Kintner [53] should Upstream unit has poor control (unsteady flow 10
be considered. If the dispersed phase is not dilute in the on level control)
continuous phase (<5 vol %), then two possible problems
Upstream unit has good control (steady flow on 5
arise with the aforementioned equations. The comparison flow control)
between the particle’s terminal velocity was made with
the superficial velocity of the continuous phase. If the dis- Equipment inside of a process unit
persed phase is not dilute, then the comparison should be Column sump feeding another column 5
made against the actual (local) velocity of the continuous
phase, which would have to take into account the space Feed to a distillation column 5
occupied by the particles. Second, in a nondilute suspension, Feed to a series of distillation columns 10
the particles may affect settling. Unlike the setting of solid
Column reflux drum (depending on control 2–5
particles, coalescence becomes important and will affect
scheme)
the drag coefficient of the droplets/bubbles, increasing the
terminal velocity but potentially changing the sphericity of Feed to a fired heater 10
the droplets. If particles resist coalescence, then the terminal
Feed to a low head charge pump 5
velocity will decrease (the droplets behave like solid particles)
and the particles may hinder movement. Hindered settling Feed to a high head charge pump 10
can be estimated by the Maude-Whitmore [54] equation, Liquid knockout drum 5
although it and other hindered settling methods contain
terms that requires empirical data. Refrigerant flash drum 2

Product directed to off-plot storage 5

13.7.3 Liquid Hold-Up
Reboilers (kettle-type) 2
The liquid hold-up volumes of vessels may govern the siz-
ing, depending on the application. The calculation of liquid Steam drums 15
hold-up is simply the multiplication of the liquid-phase flow
rate by the hold-up time desired. The geometry of the vessel During the design of a new separator, the hold-up vol-
can then be determined based on that volume. Liquid hold- umes are generally assumed to be between the tangent lines
up is often separated into two categories: hold-up and surge. of the vessel, and the volumes (or partial volumes) of the
Hold-up time is the time it takes to reduce the liquid heads are ignored; this may not be prudent in the case of a
level from normal (NLL) to low (LLL) at normal outlet flow revamp or when generating data for dynamic simulations
rates with zero inlet flow. This time should be set consider- or controller tuning in which the actual liquid volume in
ing the quality of control and reliability of the upstream the vessel needs to be considered.
facilities and the requirements of downstream equipment. The equations for the liquid volume in a vertical vessel
For vessel feeding pumps, one should also consider the are simply that of a cylinder:
potential risk to the pump should the vessel go empty.
Surge time is the time it takes to increase the liquid VL = π ⋅ r 2 ⋅ hL (13.98)
level from NLL to HLL at normal inlet flow rates with
zero outlet flow. This time should be set considering the The value of hL should be the distance between the liquid
need to insulate the upstream facilities from disruptions level of interest and the bottom tangent line.
downstream. In combination, the hold-up and surge times For a horizontal cylinder, the volume of liquid in the
should provide sufficient time for the control system to vessel is only that of a partial cylinder. The equation for the
react to changes and adjust before the separator becomes partial volume of a horizontal cylinder is shown here:
full or empty. Some operating companies like to ensure that
the surge time is sufficient for an alert human operator to   r − h 
V = L ⋅  r 2 cos −1   + ( h − r ) ⋅ 2 hr − h 
2
(13.99)
react to the situation.   r  
Liquid hold-up times for typical applications are shown
in Table 13.8. Different refinery operating companies or This equation is valid for values of h above or below the
engineering firms may use different values. Unless the oper- centerline of the vessel as seen in Figure 13.24. The cross-
ating company has specific rules, surge time should be set sectional area can be obtained by solving only the portion
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

to 25–50 % of the hold-up times shown here.

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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 339

VAPOR OUTLET

HJ HK
LIQUID LEVEL

D=2r
h

HG
dN INLET NOZZLE
Figure 13.24—Partial section of a circle. uV

HF
13.7.4 Vertical Separator Procedure
The sizing of a vertical gas-liquid separator is the most HHLL
basic case. The liquid droplets will separate from the gas

HE
phase if their terminal velocity downward exceeds the
superficial velocity of the gas flowing up the vessel, as HLL
shown in Figure 13.25. As noted previously, vertical separa-

HD
tors are selected when there is minimal liquid volume and
vapor-liquid separation governs. NLL

HC
• The particle size of the desired separation should be
selected. This is the minimum particle size that should
LLL
be carried over from the separator. A reasonable par-

HB
ticle size for most separators is 500 μm. Smaller values
(200–400 μm) are often used for flare or vent knockout
LLLL
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

drums to prevent liquid carryover into the stack or in

HA
compressor suction drums to prevent liquid ingress to
the machine.
• The Reynolds number of the selected particle size
should be determined per Eq 13.90.
• The drag coefficient of the selected particle size should
be determined with the appropriate equation from
Table 13.6. LIQUID OUTLET
• The K value can be determined from Eq 13.96 and
compared with typical values or values specific to Figure 13.25—Vertical separator schematic.
the type of internal (i.e., mesh pad, vane separator) to
be used. If the K value is significantly lower than the
typical values, this indicates that your particle size sep- each section of the vessel are shown in Table 13.9 and
aration is aggressive compared with typical petroleum Figure 13.5.
industry separators. The total height of a vessel should be between 3 and
• Use the terminal velocity of the particle as the super- 6 times the vessel diameter. The optimal length/diameter
ficial vapor velocity, and determine the required (L/D) ratio is an economic factor related to the specifics
cross-sectional area of the separator via Eq 13.94. of the situation. Parameters affecting the optimization
From this, calculate the inside vessel diameter. include
• Using the required hold-up time, calculate the hold-up • Operating and design conditions,
volume from the liquid rate flowing into the separator. • Weight,
Divide by the cross-sectional area of the vessel to deter- • Capital cost,
mine the height of liquid between the HLL and LLL. • Metallurgy,
If this value is very large (>3D), consider a horizontal • Plot space available, and
vessel or make the vessel diameter larger (i.e., liquid • Transportation limitations of fabricator to site.
hold-up governs). A simple rule of thumb that is based on the weight of
• Determine the overall dimensions of the vessel with the vessel is that higher pressures justify higher L/D ratio.
the following rules. The recommended lengths for A typical set of values for carbon steel vessels are

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340 Petroleum Refining and Natural Gas Processing

law range. Because each separation is based on the same

Table 13.9—Vertical vessel dimension density difference, the more difficult separation (assum-
Dimension Recommended Length ing the same superficial velocities and droplet sizes) will
be that in which the continuous phase has the higher vis-
HA Bottom tangent to LLLL (shutdown) should be ≥
cosity. For naphtha- through diesel-range materials, this
500 mm (10”). The minimum connection distance
of a level instrument from the bottom line is means that separating oil from water is more difficult,
approximately 300 mm. Therefore, the lowest whereas for heavier cuts the separation of water from the
control point should be slightly above this. oil phase is more difficult. Likewise, the high viscosity
of amine solutions can make separation of hydrocarbon
HB LLLL and LLL should be minimum 300 mm (6 in.)
droplets difficult.
or 1–2 minutes of hold-up time.
Droplet size selection for liquid-liquid separation can
HC + HD LLL and HLL as calculated in step 6. be difficult. For low-viscosity systems, separation of droplet
sizes of 100 μm can be expected. For high-viscosity systems
HE HLL and HHLL (shutdown) should be minimum
300 mm (6 in.) or 1–2 min of hold-up time. (>50 cP), it can be difficult to separate droplets smaller than
1000 μm (0.04 in.) in a reasonably sized vessel.
HF HHLL (maximum liquid level) and inlet nozzle For the rare case of a two-phase liquid-liquid separa-
centerline should be ½D + ½ dN tor (no vapor), the sizing calculations are done using the
HG Inlet nozzle centerline and mesh pad or vane same methods except that the superficial velocity of each
device should be ≥½D phase must be less than the terminal velocity of the desired
particle size to be separated. Whichever continuous-phase
HJ Mesh pad thickness is usually 300 mm (6 in.), but
superficial velocity results in the larger vessel diameter
other devices may be more or less.
governs. Additionally, one must consider whether the feed
HK From mesh pad/vane device to top tangent should be above or below the interface-level control range.
should be ≥½D. In general, the feed should be above the high interface
level if the separation of the light-phase droplets from
the continuous heavy phase is more difficult (i.e., more
Table 13.10—Optimal L/D Ratios residence time for the heavy liquid) and below if the reverse
is true. However, if the ratio of the flows is quite different or
Design Pressure (kPag) L/D at Minimum Weight
the desired hold-up time would result in a very large vessel,
<1000 2–3 one could consider the alternative.
∼2000 3–4 For a three-phase vertical separator, the light liquid
draw must be from the side of the vessel or from a standpipe
∼4000 4 inside of the vessel that extends above the high interface
>8000 5+ level. Another option is to include a vertical or inclined
baffle in the vertical vessel. This is most common in situ-
ations in which a small volumetric rate of oil is present in
A larger diameter than that required for vapor-liquid a great volume of water. The baffle should extend above
separation is acceptable if required to optimize the vessel the inlet nozzle to ensure that all liquid droplets fall to the
cost and weight. Using the equations provided in reverse, interface before passing over the baffle. The baffle should
one can estimate the size of particles that would carry over also extend below the light liquid draw, forcing all liquid
a larger diameter vessel. under the baffle, after which the light phase will rise up on
the outlet side of the baffle. A key issue to consider is that
13.7.5 Vertical Three-Phase Separator the cross-sectional area for determination of superficial
Procedure velocity is now only a partial circle on the side of the baffle in
In some rare cases, a vertical separator may be specified question. This can be calculated using Eq 13.99 by dividing
for three-phase (gas-liquid-liquid) separation. This is not by the vessel length.
common because a horizontal separator provides a longer
separation flow path and will perform better as a liquid- 13.7.6 Horizontal Separator Sizing Procedure
liquid disengagement device. However, in situations with Sizing of horizontal separators is basically the same logic
low liquid flows and plot space (e.g., offshore) limitations, as for vertical separators except that the motion of the
a vertical three-phase separator may be necessary. particles due to gravity is no longer parallel to the bulk
The procedure for sizing such a separator is the same as motion of the continuous phase. For dilute dispersed-phase
above, except that the engineer must check the disengage- systems, we can safely assume that the particles fall verti-
ment of the two liquid phases. In most refinery applications cally as they move horizontally with the continuous phase.
this is the separation of oil and water. The disengagement We must then determine if a given particle size will fall
calculations must be performed using oil and water as the (or rise) from the inlet nozzle to the interface before the
continuous phase to check the rate at which water droplets continuous phase reaches its outlet nozzle.
fall through oil and to check the rate at which oil droplets Figure 13.26 shows a simple horizontal vapor-liquid
rise through water. separator and a horizontal vapor-liquid separator with
The terminal velocity of the droplets of the dispersed a mesh pad disengagement device at the outlet. The
phase must be checked against the superficial velocity procedure that follows assumes that vapor-liquid separa-
of the continuous phase, using Eqs 13.89 through 13.93. tion governs the sizing; alternative cases are discussed
Liquid-liquid separations almost always fall in the Stokes’
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
briefly afterward.
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 341

INLET NOZZLE VAPOR OUTLET

HF
HHLL

HE
HLL

D=2r
HD
NLL

HC
LLL

HB
LLLL

HA
LIQUID OUTLET

INLET NOZZLE VAPOR OUTLET

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
HF

LV
HHLL
HE

HLL
D=2r
HD

NLL
HC

LLL
HB

LLLL
HA

LIQUID OUTLET

Figure 13.26—Schematics of two-phase horizontal separators.

1. Determine the terminal velocity of a liquid droplet fall- 6. Calculate the length of the vessel using the selected
ing through the vapor using Eqs 13.89 through 13.93. L/D ratio. Some engineering and operating compa-
2. Select the desired hold-up and surge times from Table nies use the full length of the vessel for separation.
13.8. Determine the hold-up and surge volumes via The author recommends deducting length to account
for the fact that the inlet and outlet nozzles are not
VH = TH QL located at the tangent line of the vessel and therefore
(13.100) the travel path of the continuous phase is shorter
VS = TS QL
than the tangent-to-tangent length of the vessel.
A good assumption for the distance from the tan-
3. Select an appropriate L/D ratio from Table 13.10. gent line to the inlet and outlet nozzles is half of the
4. Calculate a preliminary cross-sectional area using the diameter of the nozzle plus 150 mm (6 in.) to allow
following equation: for reinforcing pads and the usual distance from the
tangent to the seam weld. This should be checked
2
  3 later once the vessel mechanical drawings are avail-
π  4 ⋅ ( VH + VS ) 
able. The nozzle sizes can be sized based on normal
AT = ⋅  (13.101) hydraulic criteria for the piping (i.e., pressure drop
4   L and velocity).
 0.4 ⋅ π ⋅   
  D  7. Check that the length of the vessel is sufficient for
the liquid hold-up volume. This can be calculated by
5. Determine diameter via simple geometry. dividing the hold-up volume by the cross-sectional area
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342 Petroleum Refining and Natural Gas Processing

of the liquid phases in the vessel. You may calculate 2. The first step in the liquid-liquid disengagement is
this using Eq 13.99 with the liquid height as h. This to calculate the rise rate of the light liquid droplets
should result in a value very close to the L calculated in in the heavy liquid. As for the vertical separator,
step 6. If not, use the largest L value. you must select a droplet size that is acceptable to
8. Set the vapor space height (HF) equal to 0.25D or carryover. For low-viscosity continuous phases, 100
450 mm (18 in.), whichever is greater. If the vessel will μm or less is achievable in a reasonably sized vessel.
have a mesh pad or other disengagement device, then For high-viscosity systems, droplet sizes of 1000 μm
you must account for the space occupied by the device. may be required. Stokes’ law almost always governs
Usually, a mesh pad is approximately 150 mm thick liquid-liquid separations because of low Reynolds
and placed approximately 150 mm from the top of the number.
vessel. Additionally, you must have sufficient clearance 3. Calculate the liquid droplet rise time:
under the mesh pad to the liquid level—usually at least
300 mm (18 in.). Therefore, in such a case the dimen- H A + H B + HC + H D + H E
Θ LL = (13.104)
sion HF must be at least 750 mm (24 in.) to provide suf- uT
ficient disengagement space.
9. Using Eq 13.99, calculate the cross-sectional area of the where the dimensions designated H are shown in
vapor space using HF as h. Figure 13.27a.
10. Calculate the liquid dropout time: 4. Calculate the cross-sectional area of the heavy liquid
phase ahead of the weir using Eq 13.99. The height h
HF
ΘL = (13.102) is the numerator of Eq 13.104. In the following equa-
uT tions, this area will be designated by AHL.
5. Calculate the minimum length ahead of the weir of the
11. Calculate the minimum length of the vessel for vapor- vessel for liquid-liquid disengagement:
liquid disengagement:
QHL Θ LL
QV Θ L Lmin = (13.105)
Lmin = (13.103) AHL
AV
6. Check the hold-up time volume:
12. If Lmin is less than the length calculated in steps 6 and
7, then the vessel is large enough for disengagement. VHL = Lmin ⋅ AHL (13.106)
If not, use either a larger diameter or a large L/D ratio
and repeat calculations starting at step 5 to check that 7. If the hold-up volume calculated in step 6 is greater
all of the requirements are met or exceeded with a than or equal to that selected in step 1, then the vessel is
larger vessel. large enough. If it is not, then the hold-up time governs
the sizing. Increase the diameter or length and recalcu-
13.7.7 Horizontal Three-Phase Separators late to check the separation.
A horizontal three-phase separator is usually the most 8. You can also check the separation of the heavy liquid
common type of three-phase separator in a refinery or gas droplets from the light liquid. This is done by calculat-
processing plant because it offers the best separation of the ing the cross-sectional area of the light liquid above the
liquid phases. There are three basic types of separator that high-high interface level (HHIL) and the top of the weir
are usually used: a weir configuration, a boot configuration, (dimension HL in Figure 13.27a) using Eq 13.99 twice:
and a bucket and weir configuration. These are shown in once for the HHLL level and once for the HHIL level
Figure 13.27. and subtracting. The HHIL should be approximately
150 mm (6 in.) below the top of the weir to ensure no
13.7.7.1 Separator with Weir heavy liquid flows over the top of the weir. Then, calcu-
A weir configuration is commonly used if the volume of late the falling time for the heavy liquid droplet to fall
the heavy liquid phase is much larger than the light liquid across this distance in the length of the vessel upstream
phase and if the separation of the light liquid phase is more of the weir. Usually this is done iteratively to check the
difficult that the reverse. This is common of light hydrocar- droplet size that can be separated.
bons and water as well as light hydrocarbons and amine 9. Finally, set the distance after the weight to the tangent
solutions. line by selecting a series of liquid levels below the weir
The vapor-liquid separation is as described previously top and use the hold-up volume of the light liquid.
and can be calculated the same way. The key difference
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

here is that the length for the hold-up of the heavy liquid 13.7.7.2 Separator with Bucket and Weir
is only on the left side of the weir (as shown in the figure), A separator with a bucket and weir arrangement (see
and the hold-up of the light liquid is only on the right side Figure 13.27b) is sized in the same manner as for the weir
of the weir. The procedure for sizing the liquid sections of configuration except that the distance for liquid-separation
the vessel follow. is only up to the bucket inlet. The bucket is more of a
1. A first guess at the overall diameter of the vessel can be trough across the width of the vessel for a small volume of
obtained using the method shown above for the simple light liquid to be “skimmed” from the surface of the much
two-phase separator, combining the hold-up volumes larger heavy liquid phase. This is a common configuration
of the two liquids in Eq 13.100. The sizing of the vapor for a sour water or rich amine flash drum, in which very
space can also be done as shown above. small quantities of hydrocarbon are expected.
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 343

(a) INLET NOZZLE VAPOR OUTLET

HF
LV
HHLL

HL
HHIL

D=2r
HE
HIL

HD
NIL

HA+HB HC
LIGHT LIQUID
HOLD-UP
LIL

HEAVY LIQUID LIGHT

OUTLET LIQUID OUTLET

(b) INLET NOZZLE VAPOR OUTLET

LV
HF

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
HHLL

D=2r
HIL

NIL

LIL

LIGHT HEAVY LIQUID

LIQUID OUTLET OUTLET

(c) INLET NOZZLE VAPOR OUTLET

LV
HF

HHLL
HE

HLL
D=2r
HD

NLL
HC

LLL
HB

LLLL
HA

LIGHT
LIQUID OUTLET
HQ
HP
HN
HM

Figure 13.27—Three-phase horizontal

HEAVY separator
LIQUID schematics.
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344 Petroleum Refining and Natural Gas Processing

The bucket size is determined using the desired hold- for fabrication reasons. If the boot diameter is more
up time of the light liquid assuming level controls 150 mm than 50 % of the vessel diameter, then consider a weir
(6 in.) from the top and bottom of the bucket. Equation configuration because the heavy liquid volume is too
13.99 can be used to determine the cross-sectional area of large for a boot.
the bucket. Because there is no possibility of getting heavy 7. Once the boot diameter is determined, set the length
liquid out of the bucket, it is not necessary to check for of the boot using the desired hold-up time of the heavy
liquid-liquid disengagement therein. liquid. If the boot length is greater than 3Dboot, consider a
Finally, in a bucket and weir situation the hold-up larger diameter boot. Also, consider that the minimum
and surge time of the heavy liquid phase for purposes of distance between liquid levels should be 150–300 mm
protecting downstream equipment (i.e., a pump), one must (6–12 in.) because many level instruments only have
only consider the volume on the outlet side of the weir. For fidelity to such distances. This means an absolute mini-
such vessels, the volume after the weir can be significant mum boot length at 5 × 150 mm or 750 mm (30 in.).
such that the weir may be located some distance from the 8. Once the boot size is known, we can check the overall
outlet end of the vessel. length of the vessel. The overall length can be calculate
using
13.7.7.3 Separator with Boot
A separator with a boot is used primarily when the volume LT = Lmin + 1.25 ⋅ Dboot + dN + 300 mm (12′′) (13.109)
of light liquid is significantly larger than the volume of

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
heavy liquid or when the separation of the heavy liquid where:
from the light liquid is more difficult (light liquid is more Dboot = boot diameter and
viscous). The procedure follows. dN = light liquid outlet nozzle diameter.
1. A first guess at the overall diameter of the vessel can be The 1.25 factor and 300-mm (12 in.) allowances are
obtained using the method shown above for the simple to ensure enough space is present for reinforcing pads.
two-phase separator, combining the hold-up volumes Another check that should be performed is whether the
of the two liquids in Eq 13.100. The sizing of the vapor dimension given by LT – Lmin is greater than 2400 mm (96
space can also be done as shown above for the two- in.). If so, then a circumferential seam in the vessel may
phase separator. fall inside of the boot connection. This is not desirable.
2. The first step in the liquid-liquid disengagement is to Talk with your mechanical engineer or vessel fabrica-
calculate the drop rate of the heavy liquid droplets tor about alternatives, such as placing a girth seam
in the light liquid. As for the vertical separator, you between the outlet nozzle and the boot.
must select a droplet size that is acceptable to car- 9. Check the hold-up volume for the light liquid:
ryover. For low-viscosity continuous phases, 100 μm
or less is achievable in a reasonably sized vessel. For VLL = LT ⋅ ALL (13.110)
high-viscosity systems, droplet sizes of 1000 μm may
be required. Equations 13.89 through 13.93 are used;
10. If this is less than the desired hold-up volume, then the
Stokes’ law almost always governs liquid-liquid separa-
vessel should be made longer or the diameter increased.
tions because of low Reynolds number.
3. Calculate the heavy liquid droplet fall time:
13.7.7.4 Conclusions
H + H B + HC + H D + H E As can be clearly seen, the sizing of a three-phase separa-
ΘH = A (13.107) tor required significant iteration to ensure that all of the
uT
required criteria are met. For an existing separator that
you wish to check rate, the equations can simply be solved
where the dimensions designated H are shown in in an alternative order to determine the particle sizes that
Figure 13.27c. can be separated.
4. Calculate the cross-sectional area of the light liquid
phase using Eq 13.99. The height h is the numerator of
13.7.8 Inlet Devices to Assist Separation
Eq 13.107. In the following equations, this area will be
As can be seen clearly in Eq 13.89, the force of gravity
designated by ALL.
and droplet size are the primary parameters for separator
5. Calculate the minimum length ahead of the boot of the
performance, other than the fluid properties themselves.
vessel for liquid-liquid disengagement:
Therefore, various technologies are available to improve
separation by conditioning the inlet flow to a separator to
QL ΘH
Lmin = (13.108) improve the separation.
AL
13.7.8.1 Simple Deflection Box
6. Next, we must size the boot. The boot diameter must The first device is a simple deflection plate at the inlet to
be set such that the superficial velocity of the heavy a separator. The purpose of a deflection plate is to direct
liquid phase downward is less than the terminal rising the inlet flow to prevent entrainment or splashing. The key
velocity of a light liquid droplet. Once again, we must design parameter of an inlet box is that the velocity of the
select a droplet size. A reasonable value is 100 μm for fluid passing through the outlets of the box should be lower
most of these services. The methodology is identical than that of the fluid entering the inlet nozzle. This should
to that shown previously for a vertical separator. Boot ensure reduced velocities and minimize small droplet
diameters are usually a minimum of 600 mm (24 in.) formation.
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 345

In a vertical separator, these are usually boxes to direct ε = volumetric hold-up vapor fraction in foam (Shell found
the flow around the sides of the vessel. The designer should 0.70 for their experiments of propane boiling out of light
remember to consider the flow area out of each side of crude oil),
the box. ρL = density of liquid phase (kg/m³), and
In a horizontal separator, the inlet box usually directs ρV = density of vapor phase (kg/m³).
the inlet flow toward the head and away from the vessel This equation shows that increasing temperature
outlets. As previously stated, the inlet box should reduce the (reducing viscosity) and increased vessel size (reducing
fluid velocity from the velocity entering via the inlet nozzle. superficial velocities) will help reduce foam height if it is
A good rule of thumb is also that the inlet box depth should prone to form in a system. Additionally, because the height
be half of the distance from the top of the vessel to the of a foam generated is proportional to the inverse square
HHLL and should allow 450-mm (18 in.) clearance between of the acceleration of gravity, this supports the experience
the HHLL and the box. in the industry that cyclone-type inlet devices help prevent
foam formation [20–22].
13.7.8.2 Vane-Type Device
Vane-type inlet devices are proprietary to several suppliers, 13.8 Compressors and Pumps
including Koch-Glitsch, Shell Global Solutions (i.e., Scho- The purpose of this chapter is not to provide all of the
epentoeter), and others. These devices are most common design details of compressors and pumps, but rather to
in vertical separators and distillation columns. They are provide a brief overview with some of the key equations a
designed to evenly distribute the vapor and liquid through- process engineer may need when evaluating or specifying
out the vessel, avoiding localized entrainment of liquid this equipment.
droplets in the vapor phase. They are also designed to
minimize the formation of very small droplets as well to 13.8.1 Compressors
minimize entrainment. A compressor is a machine that increases the pressure of
a compressible fluid. The operating suction pressures can
13.7.8.3 Cyclone Devices be anywhere from deep vacuum to high positive pressures;
Cyclone devices include single and multiple cyclone discharge pressures can be anything from subatmospheric
devices that can be used in vertical and horizontal separa- to hundreds of megapascals. Compressors have been
tors. There are numerous suppliers of such technology. designed to be operated on molecular weights ranging from
The idea of a cyclone device is that by accelerating the 2 (hydrogen) to 352 (uranium hexafluoride) [56].
fluid around a conical tube, the value of g in Eq 13.89 is Compressors can be of two basic types: intermittent
increased significantly, improving separation. Addition- and continuous. Intermittent compressors operate by taking
ally, liquid droplets are forced to coalesce into larger a volume of fluid and compressing it, releasing the com-
droplets on the surface of the cyclone. The sizing of these pressed fluid, and then starting again with another volume
devices is proprietary but can be effective to ensure sepa- of fluid; because the volume of fluid admitted is always the
ration, to reduce vessel sizes, or to debottleneck an exist- same for a given compressor, these are often referred to as
ing separator. constant-volume machines. Continuous compressors can
compress the fluid volume without any interruption in the
13.7.9 Foam flow at any point; because they are based on accelerating
One problem that exhibits itself in some refinery separators the fluid using some motive force (which is constant), these
is the formation of foam. This is most often found in crude are often referred to as constant-mass machines.
preflash drums/columns, hydrocracker high-pressure sepa- Intermittent compressors can be subdivided into two
rators, and amine flash vessels. Foam can form in any basic groups: reciprocating and rotary devices. Recipro-
system, but it is more prone to form in systems containing cating compressors use a mechanical piston (or series of
surface-active species, including but not limited to carboxylic such pistons) in cylinders to compress the gas. Fluid is
and naphthenic acids, phenols, asphaltenes, heat-stable salts, admitted through a valve into the cylinder when the piston
iron-sulfide particles (in amines), or fine mineral particles. is retracted, and then the piston moves down the cylinder
The presence of water in the hydrocarbon phase can contrib- pushing the fluid against the head of the cylinder. As the
ute if there are polar surface-active species that are hydro- and piston reaches the end of the cylinder, the discharge valve
oleophilic in the system. opens, rejecting the compressed gas into the outlet piping.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Shell published an empirical correlation [55] that relates This is then repeated. Because the volume of gas admitted
fluid parameters and vessel dimensions to a predicted foam is fixed by the geometry, the properties of the fluid do not
height: affect the performance of the machine with the exception of
the power required. For a given compressor geometry, the
1.33 volumetric flow and pressure differential will be the same
1.7 × 1012 ⋅ ν L ⋅ uL3.67  ρ L 
H=   (13.111) (power and temperatures will of course vary). Reciprocating
g 2 ⋅ ui 0.67 ⋅ (1 − ε )6.32  ρ L − ρ V  compressors are common in the hydrocarbon processing
industry for smaller flows with high pressure ratio require-
where: ments, such as for natural gas transmission and hydrogen
H = foam height (m), makeup to hydrotreaters. For low-molecular-weight gases
ν = kinematic viscosity of the liquid (m²/s), such as hydrogen, the thermodynamic efficiencies of these
uL = superficial downward velocity of liquid (m/s), machines can approach 100 %.
ui = inlet velocity of mixed-phase fluid (m/s), A rotary compressor can be of various types, including
g = acceleration due to gravity = 9.81 m/s², sliding-vane, liquid-ring, helical-lobe, and straight-lobe
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346 Petroleum Refining and Natural Gas Processing

screw devices. These machines differ from reciprocating operate at pressures up to 68 MPa (10,000 psi). These are
machines as the machinery rotates on a shaft and they do some of the most common compressors in the hydrocarbon
not have inlet or outlet valves, but they are intermittent. processing industry and are used for wet gas compressors in
A volume fluid is admitted into the first chamber as the FCCs and cokers; recycle compressors in hydroprocessing
rotor moves over the inlet port. As the rotor turns, the units; and for larger flow instrument air, fuel gas, or nitrogen
chamber in which the fluid is trapped becomes smaller compression.
because of the geometry of the rotor and casing. Once the Axial compressors are large-volume machines that
chamber reaches the outlet port, the now-higher pressure are characterized by the fluid moving along the shaft
fluid exits via the outlet port. The direction of travel for of the machine through a series of unshrouded blades.
the fluid may be radial (sliding-vane, liquid-ring) or axial Each stage of the machine consists of one set of rotating
(screws), but the principle is the same. blades, followed by a stationary set of blades. The fluid
Sliding vane and liquid-ring compressors are often passes through the rotating blades, where it is acceler-
used in low-pressure applications and as vacuum pumps. ated and increased in a pressure. The fluid then slows
They have capacity ranges from 3 to 27,000 m³/h through the static blades and increases in pressure further.
(2–16,000 cfm) and generally with a pressure ratio of 3–5 Because each stage is only capable of producing a small
in a single stage. pressure increase, these machines are always built as mul-
Screw compressors are used in a wide variety of appli- tistage compressors. The blades of an axial compressor are
cations (e.g., instrument air, nitrogen, flare gas recovery, made to exacting tolerances and often of expensive materi-
PSA tailgas) and have capacity ranges of 800–60,000 m³/h als, making these expensive, but often more economic for
(500–35,000 acfm) with pressure ratios in a single stage of large volume applications. The most common application
approximately 3. Screw compressors can be of either dry of the axial compressor is in the turbo-fan (jet) engine
or flooded type. The dry type uses timing gears to ensure used in commercial and military aircraft. Axial compres-
the perfect meshing of the screws; the flooded uses an sors for process use can be built from 120,000 to 1.7 × 106
oil layer to keep the screws from touching. The flooded m³/h (70,000–1,000,000 acfm). Axial compressors in the
type can handle higher compression ratios because the petroleum industry are generally limited to natural gas
lubricating fluid can be used to remove some of the heat pipelines and air compressors for air separation facilities
of compression. However, in fluids containing dust, a because there are few other applications that require the
flooded screw is not reliable because the dust will contami- volumetric capacity.
nate the lube oil. Mixed-flow compressors offer some of the features of
Continuous compressors can be divided into two centrifugal and axial machines. The rotors are more like a
types: ejectors and dynamic machines. An ejector is a centrifugal compressor, but the blades are angled along the

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
low-efficiency machine that uses Bernoulli’s principle shaft (in the axial direction). These provide a unique head-
that a high-velocity motive fluid can produce a low static capacity offering, which is typically used for gas pipeline
pressure and that slowing down the fluid will raise its booster compressor services.
pressure. Ejectors have no moving parts and are therefore All compressors, regardless of type, are governed by
highly reliable and low maintenance (unless the fluids the same basic equations. All compressible fluids obey the
contain solids that erode the ejector). Ejectors are often real gas law:
used in vacuum applications in which very low pressures
are required. Motive fluids for ejectors are usually steam PV = nZRT (13.112)
or gas, but liquids can also be used. In such services, these
may be referred to as jet pumps. It must be noted that the compressibility factor, Z, is
Dynamic compressors impart energy to the fluid dependent on pressure, temperature, and composition.
using a set of rotating blades. The energy is exhibited as Estimating the Z value for a given fluid can be done using
velocity and pressure increase, although much of the pres- thermodynamic charts or calculated using one of various
sure increase occurs in the stationary elements. Because equations of state. A commercial simulator program is the
these machines use force to accelerate the gas, the density fastest way to estimate this value.
and molecular weight of the gas will affect the performance In theory, compression could be isothermal or adia-
of the machine. In general, for a given compressor the mass batic (or something in between). However, because building
flow will be constant at a given power input, with volumetric an isothermal compressor would be difficult, most operate
flow and pressure varying with varying fluid properties. closer to the adiabatic mode. For adiabatic compression, on
Dynamic compressors come in three forms: centrifugal, the basis of Eq 13.113,
axial, and mixed flow, which combines the features of the
first two.
PV γ = constant (13.113)
Centrifugal compressors function by admitting fluid
into the rotor near the shaft and radially accelerating the
where γ is the ratio of the specific heats of the gas,
fluid toward the edge of the rotor. As the fluid is pushed
outward by the blades of the spinning rotor, it moves faster
Cp Cp
and increases in pressure. The fluid then decelerates in a γ= = (13.114)
diffuser that creates more pressure. These have a capacity Cv Cp − R
range of 1700–250,000 m³/h (1000–150,000 acfm) with a
compressor ratio generally limited to approximately 3 for The latter part of this equation is generally used in industry,
a single stage. They are often built as multistage machines although it only applies to ideal gases (i.e., low-pressure
with multiple rotors on one shaft and have been built to gases with minimal intermolecular interactions). This
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 347

is because specific heats were more easily measured at Similar to adiabatic compression, we can calculate the
constant pressures, and even calculating Cv rigorously is outlet temperature of the compressor by rearranging
somewhat involved. However, with modern simulation Eq 13.119. However, unlike the adiabatic compression pro-
programs, calculation of a rigorous (and real) specific heat cess, the temperature we calculate is the actual discharge
at constant volume is possible. However, you may find that temperature, assuming no jacket cooling of the compressor.
vendor and performance data for compressors are still The shaft power required by an intermittent or dynamic
based on the ideal relationship. compressor can be calculated from the adiabatic or poly-
Although it is essentially impossible to build an adiabatic tropic head via the following:
machine (it would be isentropic and completely reversible),
the minimal heat losses in a positive displacement machine mhx
Wx = (13.122)
mean that it operates very close to adiabatically. ηx
The adiabatic head, or ideal enthalpy change, of a
compressor is calculated via where the subscript x indicates either polytropic or adia-
batic values. In this equation, m designates mass flow, and
 γ −1  you must ensure that you use a consistent set of units to
γ  P2  γ 
had = ∆Hideal = Zavg RT1   − 1 (13.115) obtain a valid result.
γ − 1  P1  
  For a multistage compressor, the pressure ratio per
stage can be determined by
The discharge temperature of an adiabatic compressor can
then be calculated via P2
rS = S r = S (13.123)
γ −1 P1
P  γ

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
T 2′ = T1  2  (13.116)
 P1  The question of how to determine the correct number of
stages depends on the inlet temperature of the gas, what
This is the theoretical discharge temperature assuming is a reasonable interstage cooling temperature, and what
zero heat losses. This is never quite true, but for many type of compressor you are specifying. In most facilities,
reciprocating compressors it will give a reasonably close the interstage cooling temperature that can be obtained is
approximation, particularly for fluids of low molecular limited by the use of a low-cost cooling medium, such as
weight. If you know the actual adiabatic efficiency, you can air or water. This usually limits the suction temperatures
calculate the actual discharge temperature via of each stage to approximately 30–50°C, depending on
location. The discharge temperatures should be limited to
(T 2′ − T1 ) 150°C (300°F) for reciprocating compressors (as recom-
T2 = T1 + (13.117) mended in reference [57]). Reciprocating compressors in
ηad
hydrogen service (or any gas mixture with a low molecular
weight) should be limited to a discharge temperature of
Dynamic compressors are less thermodynamically efficient 130°C (266°F) [57]. The maximum recommended dis-
than positive displacement machines; therefore, they oper- charge temperature should be limited to 260°C (500°F)
ate according to the polytropic equation: for centrifugal, axial, and screw compressors. The actual
temperature limits of rotary compressors are dependent on
PV n = constant (13.118) the material selection, lubricants, and process gas. Keep-
ing temperatures below 200°C (390°F) is good practice to
where n is the polytropic exponent. This is determined from
provide lower maintenance requirements and lower cost
experiment by measuring the inlet and outlet conditions of
materials of construction.
the compressor:
Dynamic compressors are often described by com-
n −1 pressor maps, which are similar to pump curves. An example
T2  P2  n
(13.119) compressor map is shown in Figure 13.28.
= 
T1  P1  In this figure, the surge line is the minimum stable flow
of the compressor. At these flows, the compressor blades
The polytropic exponent is related to the ratio of specific “stall,” much like the wings on an aircraft at low flow. The
heats by the polytropic efficiency: result is that high-pressure gas flows backward through part
of the machine and then reverses back to forward flow. This
n −1 γ −1 occurs repeatedly, and if the machine operates for any sig-
= (13.120) nificant period of time in this mode then machine damage is
n γη p
likely to occur. Because operating to the left of the surge line
The polytropic head is determined via an adjusted version will damage the machine, most manufacturers recommend
of Eq 13.115 where we replace the ratio of specific heats by setting control alarms above the surge line by a few percent
the polytropic exponent: such that warnings occur before surge happening.
The stonewall line is the point at which the compressor
 n −1  reaches choke, or near-sonic flow, usually in the diffuser at
n  P2  n  the outlet of a stage. Because you cannot accelerate the fluid
hp = Zavg RT1    − 1 (13.121)
n − 1  P1   past the sonic velocity in a dynamic machine, there is no way
  to push more fluid through the machine. Operating near the
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348 Petroleum Refining and Natural Gas Processing

600

500
OP
ER
AT

DIFFERENTIAL PRESSURE
ING
400 RA
NG L
E AL
N EW
O
ST

E
300

RG
SU

10
8%
200

SP
0%
92
83

EE
%
%

SP
SP

D
EE
EE

D
100 D

D
0
1000 2000 3000 4000 5000 6000 7000 8000 9000
VOLUMETRIC FLOW

Figure 13.28—Example centrifugal compressor map.

stonewall line will not damage the machine. Dynamic com- D 

2
N 
2

pressors must operate between these two lines. H2 =  2  H1 or H2 =  2  H1 (13.125)

There are numerous texts that go into much more detail  D1   N1 
on compressor selection, sizing, and operation [56,58,59].
3 3
Additionally, the reader is recommended to review industry D  N 
standard documentation, specifically API Standards 617 W2 =  2  W1 or W2 =  2  W1 (13.126)
 D1   N1 
(centrifugal and axial), 618 (reciprocating), and 619 (screw)
[57,60,61].
One can estimate the performance of a pump with a different
13.8.2 Pumps impeller size or speed using these relationships.
Similar to compressors, pumps are for increasing the pres- Centrifugal pumps can suffer decreased performance
sure of a fluid, the difference being that pumps are used for and even pump damage if cavitation occurs in the pump.
essentially incompressible fluids—liquids and supercritical Cavitation is the phenomenon by which vapor bubbles form
(dense-phase) fluids. Similar to compressors, there are because of a drop in pressure below the vapor pressure of
numerous types of pumps, but generally they fall into two the liquid. As the pressure then rises, the bubbles will collapse
categories: dynamic and positive displacement. back to the liquid phase. Pumping of bubbles is inefficient,
Dynamic pumps are those that increase pressure by and the violent collapse of said bubbles can damage the
accelerating a liquid using the kinetic energy input of an internal parts of the pump. Preventing cavitation is done
impeller. Most dynamic pumps are centrifugal, although there by ensuring that the system in which the pump is installed
are some axial pumps. Because the centrifugal pump is the avoids pressures in the pump impeller eye that are below
most commonly used pump in the process industries, it will the vapor pressure of the fluid. The parameter that is used
be the focus of this section. for this is called the net positive suction head (NPSH).
Centrifugal pumps increase the pressure of a liquid The required net positive suction head (NPSHR) of
primarily through centrifugal force. The pump impeller is pump, shown in Figure 13.6, can be estimated before a ven-
spun at high speed, and fluid admitted through the eye of the dor pump curve is available using the relationship between
impeller is accelerated toward the outside of the impeller. suction-specific speed and NPSHR:
The fluid is then slowed in a diffuser or volute, which con- 4

verts velocity to pressure. N Q 3

NPSHR =   (13.127)
The performance of a centrifugal pump follows a declin-  NSS 
ing head profile with capacity as shown in Figure 13.29,
which displays a centrifugal pump curve.
where:
Because the head developed by the pump rises with
NSS = suction-specific speed,
declining flow, this is a good fit with a control valve for
Q = flow (usgpm), and
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

controlling the flow of the pump.

N = speed of the pump (rpm).
The relationship among the impeller size, pump speed,
This equation should be used using U.S. customary
flow, and head are known as the fan laws because they were
units. For preliminary estimates, the suction-specific speed
first developed for such equipment, although their use is
should be assumed to be between 8000 (water) and 11,000
most common for centrifugal pumps:
(hydrocarbon). For double suction pumps, use half the flow
in Eq 13.127.
D2 N
Q2 = Q1 or Q2 = 2 Q1 (13.124) The NPSH that is available from the system, or NPSHA,
D1 N1 can be calculated using
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 349

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 13.29—Typical pump curve. Source: Curve from www.pump-flo.com pump selector, courtesy of Afton Pumps, Inc.

Psrc − ∆Pf − Pvap perating in parallel to obtain a pump with a low enough
o
NPSHA = + hs (13.128) NPSHR.
ρg
For fluids that contain dissolved gases, it is possible to
where: operate a pump with some gas bubbles in the pumped fluid,
Psrc = absolute pressure above the liquid in the source vessel without significant performance degradation or damage.
or tank; This is because dissolved gases behave differently than
ΔPf = frictional pressure drop between the source and the vaporized liquid. In a water pump, if the pressure drops
pump, including fittings, strainers, valves, and inlet losses below the vapor pressure of water, then steam bubbles will
at the drum; form. The collapse of these bubbles is a thermodynamic
Pvap = vapor pressure of the fluid at the pumping tem- phase change and happens very quickly because there is
perature; no other limitation. For water with some dissolved gas, the
ρ = fluid density; bubbles can form in the suction piping, but they may not
g = acceleration of gravity; and collapse violently in the pump; the process of re-dissolving
hs = elevation difference between the liquid level and the the gas in the water is limited by mass transfer, not thermo-
pump. dynamics. Because this is orders of magnitude slower, there
For a new pump, one should set the NPSHA equal will be no damage to the pump.
to NPSHR plus a margin (usually 1–2 m) and set For these pumps, rather than using the vapor pressure
the suction vessel elevation by adjusting hs to balance of the bulk fluid in Eq 13.128, one can use a pseudovapor
the equations. For existing installations, it may require pressure [62,63,64]. A few simple rules can be used to help
selecting a lower speed pump or multiple smaller pumps decide how to approach this
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350 Petroleum Refining and Natural Gas Processing

• If the dissolved gases are similar to the fluid (i.e., Positive displacement pumps are those that increase pres-
light hydrocarbons in heavy hydrocarbons), then it sure by moving a discrete volume of liquid from the suction
is generally safest to assume that the fluid is at the to discharge side of the pump. The discharge pressure is
bubble point. defined not by the pump but by the discharge system. The
• If the dissolved gas is air (in subcooled water), then you maximum discharge pressure of a positive displacement
can generally assume that the dissolved gas is irrelevant pump is limited only by the power input and the mechanical
if the pump suction level is above the pump nozzle. integrity of the pump. Positive displacement pumps can be
• If the dissolved gas is somewhat soluble in water (i.e., reciprocating or rotary.
ammonia, H2S) you should use a pseudovapor pressure Reciprocating pumps utilize a piston or diaphragm to
method. displace the liquid. This piston or diaphragm can be moved
• If the dissolved gas is hydrogen in hydrocarbon, then by a motive fluid, such as steam or air, or mechanically using
you should use a pseudovapor pressure method. a piston rod connected to a crankshaft and thus driven by a
The pseudovapor pressure method is as follows: turbine, engine, or electric motor. In piston-type reciprocating
• Simulate the process stream with the expected dissolved pumps, the piston can be single or double acting, meaning the
gases using a commercial simulator program. Determine piston displaces fluid on one or both ends of each stroke. As
the pressure required (at operating temperature) that the piston moves away from the cylinder head, the chamber
results in 2.5 vol % vapor (actual volume). becomes larger, and liquid is admitted via a suction check
• This can be done for any pump, but as noted above, valve; the piston then moves back toward the cylinder head,
the pseudovapor pressure for the first case will likely pushing the fluid out the discharge check valve. A recipro-
be more than 95 % of the bubble-point vapor pressure cating pump may be referred to as a simplex, duplex, or
whereas for the second it will likely be less than the triplex pump; this is simply a designation of how many
actual vapor pressure. It is only for the third and fourth cylinders are mounted in a single base or frame (1, 2, or 3).
cases that it is significant. Reciprocating pumps have the downside of producing
This is acceptable because centrifugal pumps can han- pulsating flow on the suction and discharge sides. This
dle 2–3 % vapor in the inlet if this vapor is not going to can be somewhat mitigated using a pulsation dampener.
“condense” in the pump. Methods have been published A pulsation dampener can be a diaphragm device or a
[57,64] providing a route for this without using a simulator direct pressurization device, with the only difference being
for rigorous thermodynamic prediction of vapor pressure; whether there is a separation between the gas that provides
however, in most instances today, a simulator is the fastest the “dampening” pressure. The sizing of the pulsation
route. dampener depends on the speed and size of the pump:
The power requirements of a centrifugal pump are
easily calculated via Eq 13.129: 5⋅ Q
V= + 1.5 ⋅ VD (13.134)
60 ⋅ n ⋅ NC
Q ⋅ ∆P
Wshaft = (13.129)
η where:
Q = flow of the pump,
where the units are consistent (e.g., power in W, flow in n = speed of the pump (rpm), and
m³/s, differential pressure in Pa). Because most designers NC = number of acting cylinders (e.g., 1 for single acting
do not work in base units, common versions of this equation simplex pump, 4 for double-acting duplex, etc.).
are shown below for various unit sets: The second term of the equation is the minimum gas
volume behind the diaphragm, which is equal to at least 1.5
Qusgpm ⋅ ∆Ppsi times the volume of a single cylinder displacement of a piston.
Whp = (13.130)
1714 ⋅ η This equation is best for pumps operating below 100 rpm.
For speeds above 100 rpm, multiple the volume calculated
using Eq 13.134 by the pump speed divided by 100.
Qm3 / h ⋅ ∆PkPa
WkW = (13.131) One parameter that is critical for all pumps is the
3600 ⋅ η NPSH, which in the case of the reciprocating pump must be
sufficient to ensure that the pump cylinder fills completely
Often the pressure rise across a pump is described in terms with liquid during the suction stroke. Because reciprocat-
of total developed head, which is the equivalent static ing pumps have a dynamic valve action, the NPSH of such
head of fluid. This is done because pumps generate constant pumps is usually specified in terms of pressure, not head, as
“head,” not pressure; therefore a change in fluid specific is done for centrifugal pumps. For this reason, some pump
gravity will result in a change in differential pressure at a manufacturers also refer to the NPSH of a reciprocating
given speed. Therefore, Eqs 13.130 and 13.131 are often pump as the net positive inlet pressure (NPIP). The NPSH
written in terms of developed head: or NPIP available to a reciprocating pump is defined by

Qusgpm ⋅ ∆H ft ⋅ SG NPSH A = Psrc + ρ ghs − ∆Pf − ( Pvap + ρ ghHI ) − ρ gha (13.135)

Whp = (13.132)
3960 ⋅ η
where:
Psrc = source pressure,
Qm3 / h ⋅ ∆Hm ⋅ ρ kg / m3 ⋅ gm / s3 Qm3 / h ⋅ ∆Hm ⋅ SG
WkW = ≅ (13.133) hs = liquid static head from the source liquid height to the
3.6 × 10 ⋅ η
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
6
367 ⋅ η suction connection on the pump,
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 351

ΔPf = frictional pressure drop in the suction piping, However, unlike reciprocating pumps, rotary pumps do not
Pvap = vapor pressure of the fluid, produce pulsating flow and there is therefore no need to
hHI = NPSH margin recommended by the Hydraulic Institute consider acceleration head in the NPSHA calculation.
(7 ft/2.13 m), and However, similar to reciprocating pumps, the NPSH is usually
ha = acceleration head. reported in pressure units, not head of liquid (and is called
Unlike centrifugal pumps, the acceleration head of the NPIP, not NPSH).
fluid in a reciprocating pump is not negligible because of the
pulsating nature of the machine. It may be determined via 13.9 Filtration
Filtration is a unit operation in refineries that is often
Luavg nC overlooked by those designers with limited experience in
ha = (13.136)
gk operations because the challenges that can be solved by
filtration are not easily seen from a heat and material
where: balance. Solid particles in fluid streams can come from
L = actual length of the suction piping, several sources, including but not limited to mineral fines
uavg = average velocity in the suction piping, (i.e., clay, sand) from the crude oil reservoir, asphaltene
n = pump speed (rpm), precipitates, polymers and gums from unstable products
g = gravitational constant (9.81 m/s², 32.174 ft/s²), and reacting or oxidizing in storage or during processing (e.g.,
k = compressibility factor of the liquid (2.5 for LPG or hot cracked stocks, chemicals used in oil well maintenance),
oils, 1.4 for water and similar fluids). catalyst fines, coke particles, and corrosion products. Such
The value of C is based on the pump configuration solids can poison or plug catalyst beds; foul heat transfer
(Table 13.11). equipment and column internals; and abrade piping, valves,
The power requirements of a reciprocating pump are instruments, and equipment.
easily determined, although you will require data from a Some solids in a refinery can be of significant size,
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

pump vendor with regards to the efficiency of the pump. particularly if the facility contains a vacuum tower, coker,
visbreaker, or other unit that cracks the product. However,
Q ⋅ ∆P most particles that refineries are concerned with are small
Wbrake = metric (m3 /h, kPa)
3600 ⋅ ηvηhηm (<500 μm). Very large particles (>12 mm / 0.5 in.) will gener-
(13.137) ally settle in tanks, and vessels are only a problem if they
Q ⋅ ∆P
Wbrake = US customary (usgpm, psi) are in sufficient quantity to block outlets or reduce storage
1714 ⋅ ηvηhηm volumes.
Strainers can be used to prevent large particles, gener-
The efficiency terms are the volumetric, hydraulic, and
ally those larger than 5 mm that can damage pumps, valves,
mechanical efficiencies. For the product of the volumetric
or plug tower internals. These are usually of a basket or
and hydraulic efficiencies, it is relatively safe to assume
“T” type, allowing for operators to isolate the strainer
approximately 0.90. For the mechanical losses, it is depen-
and remove the material from the strainer when the unit
dent on the stroke and operating pressure (as a percentage
becomes plugged. These are commonly included on pump
of the maximum the pump can produce):
suctions from tankage in solids-bearing services, but they
ηm ≅ − 4.7831 ⋅ ln ( FMOP )2 + 48.638 may also be included on such process streams as coker/
(13.138) FCC main fractionator bottoms, atmospheric and vacuum
⋅ ln ( FMOP ) − 37.964
distillation bottoms products, HVGO pumparound draws,
where FMOP is the percentage of maximum operating pres- wash oil/slop wax draws, and hydrocracker fractionators
sure at which the pump is operating. The equation is bottoms.
approximate because it was curve-fitted by the author from These differ from temporary suction strainers (TSS),
a limited dataset and should be used with caution. which are usually of a cone (i.e., witch-hat) type, which are
Rotary displacement pumps are similar to reciprocating installed in pump suctions for startups of new facilities and
pumps in that they move a discrete volume of fluid from the after maintenance shutdowns to prevent materials left after
low-pressure suction to a higher pressure discharge system. construction/maintenance (i.e., bolts, weld slag, gloves) from
entering the pump suctions.

Table 13.11—Reciprocating Pump 13.9.1 Filter Selection

Acceleration Head Constant Filters can be of many types, including replaceable cartridge
Type C Factor or bag filters, continuous backwashing filters, sand filters,
activated carbon beds, and precoat filters. Cartridge filters are
Simplex, single-acting 0.400 significantly less expensive, but they have higher operating
Simplex, dual-acting 0.200 costs because you must regularly replace the filter elements.
Backwashing filters have lower operating costs, but they
Duplex, single-acting 0.200 will have significant instrumentation that will require main-
Duplex, dual-acting 0.115 tenance. Sand filters are usually only used for treating water
to remove solids. Precoat filters are filters with elements that
Triplex, single- or dual-acting 0.066
must be coated with a medium that provides the filtering
Quintuplex, dual-acting 0.040 action. Common precoat materials are diatomaceous earth
and wood pulp. The precoat material is disposed of after
Septuplex, dual-acting 0.028
it has been used. Activated carbon beds are often used to
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352 Petroleum Refining and Natural Gas Processing

remove insoluble (or partially soluble) materials from a A nominal rating indicates that the filter will retain or
stream where that component has a high affinity for acti- capture some percentage less than 99.98 % of the particles
vated carbon. Precoat filters are also often used to remove of the rated size. This is often between 60 % and 85 %.
insoluble liquids from aqueous solutions, such as removing Some filters rated as nominal can actually reach something
oil from amine or steam condensate. approaching an absolute rating once a cake of filtered mate-
The selection of which filter is corrected for a given rial builds up on the filter media. This is because the cake
application depends on several factors: becomes the filter media and can improve the filtration of
• Fluid hazard/risk: If the risk of exposing operations smaller particles. When discussing this with filter suppliers,
personnel to the process fluid during the task of be sure to ask if their filter performance is with a clean filter
changing a filter cartridge is deemed to be too high, or after a cake has built up. If the quoted performance is
then a backwashing filter may be preferable. This may after the cake has accumulated, then the clean performance
be due to the toxicity, temperature, or pressure of the may be less effective. Additionally, higher pressure drops
process. may be required for these types of installations. Filter selec-
• Filtering temperature: For services in which filtration of tions for some processes as are done typically in a modern
the process fluid occurs at high temperature because of refinery are shown in Table 13.12.
viscosity concerns (i.e., hydrocracker feeds), it may be
desirable to use a backwashing filter because cooling
the filter for cartridge replacement may be problematic References
because of plugging and draining concerns. [1] Manning, F.S., and Thompson, R.E., Oilfield Processing of
Petroleum, Volume Two: Crude Oil, PennWell Books, Tulsa,
• Solids load: For services in which the solids load is OK, 1995, pp. 145–158.
expected to be high, a backwashing filter may be pref- [2] Biglari, M., Iikhaani, S., Alhajri, I., and Lohi, A., “Process
erable because changing cartridges every shift or day is Design, Simulation and Integration of a New Desalter in the

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very expensive in materials and labor. Crude Distillation Unit of a Refinery,” Int. J. Oil, Gas & Coal
Filter media must also be selected to be compatible Technol., Vol. 3, 2010, pp. 350–361.
with the process fluids. Filter media may be constructed [3] Geankoplis, C.J., Transport Processes and Separation Process
Principles, 4th ed., Prentice Hall, Upper Saddle River, NJ,
from several materials, including natural fibers (e.g., cotton, 2003.
cellulose), polymers (e.g., polypropylene), metal (e.g., stainless [4] McCabe, W.L., Smith, J.C., and Harriott, P., Unit Operations
steel, nickel alloys), and sintered metals. The selection of of Chemical Engineering, 7th ed., McGraw-Hill, New York,
the proper material should be done in consultation with a 2005.
materials engineer. [5] Manning, F.S., and Thompson, R.R., Oilfield Processing: Crude
Oil, PennWell, Tulsa, OK, 1995.
Cartridge and backwash filters are often sold with a basis
[6] Perry, R.H., and Green, D.W., Perry’s Chemical Engineers’
for what size of particles they will allow to pass through the Handbook, 7th ed., McGraw Hill, New York, 1997.
filter. There are two general classes of filter material: those [7] Riazi, M.R., Characterization and Properties of Petroleum
with an absolute rating and those with a nominal rating. An Fractions, ASTM Manual 50, ASTM International, West
absolute rating indicates that the filter material will allow Conshohocken, PA, 2005.
nothing (OSU-F2 test requirement is 99.98 % retention) to [8] HYSYS, “Reference Volume 1, Version 1.1,” HYSYS Reference
Manual for Computer Software, HYSYS Conceptual Design,
pass through the filter that is larger than specified. There- Hyprotech Ltd., Calgary, Alberta, Canada, 1996.
fore, a fluid containing 10,000 particles/L that are larger [9] Peters, M.S., and Timmerhaus, K.D., Plant Design and Eco-
than 10 μm would have only 20 particles larger than 10 μm nomics for Chemical Engineers, McGraw-Hill, New York, 2003.
after passing through a 10-μm absolute filter. [10] Sinnott, R.K., Coulson & Richardson’s Chemical Engineering,
3rd ed., Vol. 6, R.K. Sinnott, Ed., Butterworth-Heinemann,
London, 1999.
[11] Kister, H.Z., “Effects of Design on Tray Efficiency in Com-
Table 13.12—Typical Filter Configurations mercial Towers,” Chem. Eng. Prog., Vol. 42, 2008, pp. 39–47.
[12] Distillation Equipment Company, Staffordshire, United
Service Type
Kingdom, http://www.traysrus.com/ (accessed November 14,
Hydrotreater feed 2011).
[13] Euroslot Kdss, http://www.euroslotkdss.com/mtri/tower-inter-
Naphtha/kerosene/ Cartridge, 10 μm absolute. Backwashing nals/distillation-trays.html (accessed January 3, 2011).
diesel may be desired in coker naphtha service [14] Koch Chemical Technology Group, LLC, Wichita, KS, 2009,
if storage of coker naphtha. http://www.koch-glitsch.com/koch/faq/faq.asp.
[15] Kister, H.Z., Distillation Operations, McGraw-Hill, New York,
Heavy gas oil/ Backwashing, 10 μm absolute. Especially 1990.
residues if upstream units contain coke fine [16] Binous, H., “Equilibrium-Staged Separations Using MAT-
producing processes. LAB and MATHEMATICA,” Chem. Eng. Prog., Vol. 42, 2008,
pp. 69–73.
FCC or coker main Cartridge, 100+ μm absolute. Larger
[17] Kaes, G.L., Refinery Process Modeling—A Practical Guide to
fractionator, vacuum sizes in cokers, smaller in FCC. Strainers Steady State Modeling of Petroleum Processes, Athens Printing
tower wash oil, can be used if spray nozzles can handle Company, Athens, GA, 2000.
HVGO draw particles up to 1 mm. [18] Hines, A.L., and Maddox, R.N., Mass Transfer, Fundamentals
and Applications, Prentice Hall, Inc., Upper Saddle River, NJ,
Sour water service Cartridge/bag, 50 μm absolute.
1985, p. 509, Table B-8.
Amine service Cartridge/bag, 5–10 μm absolute. [19] Andersson, E., “Minimising Refinery Costs Using Spiral Heat
Exchangers,” Petrol. Technol. Quart., Q2, 2008.
Backwashing may be an option if solids
[20] Underwood, A.J.V., “Calculation of the Mean Temperature
load is very high. Rich amine filtration is
Difference in Multipass Heat Exchangers,” J. Inst. Petrol.
more effective at keeping process clean. Technol., Vol. 20, 1934, pp. 145–158.
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Chapter 13 n Design Aspects of Separation Units and Processing Equipment 353

[21] Bowman, R.A., Mueller, A.C., and Nagle, W.M., “Mean Tempera- [42] “Introduction to Fired Heater Design,” http://www.heaterdesign
ture Difference in Design,” Trans. Am. Soc. Mech. Eng., May, .com/.
1940, pp. 283–293. [43] Berman, H.L., “Fired Heaters-I, Finding the Basic Design for
[22] Maxwell, J.B., Data Book on Hydrocarbons, Standard Oil Your Application,” Chem. Eng., Vol. 85, June 19, 1978, pp. 99–104.
Research Company, New York, 1950. [44] Berman, H.L., “Fired Heaters-II, Construction, Materials,
[23] Wales, R.E., “Mean Temperature Difference in Heat Exchang- Mechanical Features, Performance Monitoring,” Chem. Eng.,
ers,” Chem. Eng., February 23, 1981, pp. 77–81. Vol. 85, July 31, 1978, pp. 87–96.
[24] Standards of the Tubular Exchanger Manufacturers Association, [45] Berman, H.L., “Fired Heaters-III, How Combustion Condi-
9th ed., TEMA, Tarrytown, NY, 2007. tions Influence Design and Operation,” Chem. Eng., Vol. 85,
[25] Gulley, D.L., “How to Calculate Weighted MTDs,” in Heat August 14, 1978, pp. 129–140.
Exchanger Design Book, Gulf Publishing Company, Houston, [46] Berman, H.L., “Fired Heaters-IV, How to Reduce Your Fuel
TX, 1968, p. 13. Bill,” Chem. Eng., Vol. 85, September 11, 1978, pp. 166–167.
[26] Nesta, J., and Bennett, C.A., “Reduce Fouling in Shell-and- [47] Fired Heaters for General Refinery Service, 4th ed., API Standard
Tube Heat Exchangers,” Hydrocarbon Processing, July 2004, 560, American Petroleum Institute, Washington, DC, 2007.
pp. 77–82. [48] Patel, S., “Simplify Your Thermal Efficiency Calculation,”
[27] Brown, R., “Design of Air-Cooled Exchangers—A Procedure Hydrocarbon Processing, July 2005, pp. 63–69.
for Preliminary Estimates,” Chem. Eng., Vol. 85, March 27, [49] ZareNezhad, B., “New Correlation Predicts Flue Gas Sulfuric
1978, pp. 108–111. Acid Dewpoints,” Oil & Gas J., Vol. 56, September 21, 2009,
[28] Kumana, J.D., and Kothari, S.P., “Predict Storage-Tank Heat pp. 60–63.
Transfer Precisely,” Chem. Eng., March 1982, pp. 127–132. [50] Pierce, R.R., “Estimating Acid Dewpoints in Stack Gases,”
[29] Churchill, S.W., and Bernstein, M., “A Correlating Equa- Chem. Eng., Vol. 84, Issue 8, 1977, pp. 125–128.
tion for Forced Convection from Gases and Liquids to a [51] Verhoff, F.H., and Banchero, J.T., “Predicting Dewpoints of
Circular Cylinder in Crossflow,” J. Heat Trans., Vol. 99, 1977, Flue Gases,” Vol. 70, Chem. Eng. Prog., 1974, pp. 71–72.
pp. 300–306. [52] Clift, R., Grace, J.R., and Webber, M.E., Bubbles, Drops and
[30] Churchill, S.W., and Chu, H.H.S., “Correlating Equations Particles, Academic Press, New York, 1978.
for Laminar and Turbulent Free Convection from a Hori- [53] Grace, J.R., and Weber, M.E., “Hydrodynamics of Drops and
zontal Cylinder,” Int. J. Heat Mass Trans., Vol. 18, 1975, Bubbles,” in G. Hetsroni, Ed., Handbook of Multiphase Sys-
pp. 1049–1053. tems, McGraw-Hill, New York, 1982, pp. 1–204.
[31] Chato, J.C., “Laminar Condensation inside Horizontal and [54] Maude, A.D., and Whitmore, R.L., “A Generalized Theory of
Inclined Tubes,” ASHRAE Journal, Vol. 4, 1962, pp. 52–60. Sedimentation,” Br. J. Phys., Vol. 9, 1958, pp. 477–482.
[32] Dittus, F.W., and Boelter, L.M.K., Publications on Engineering, [55] Barber, A.D., and Wijn, E.F., “Foaming in Crude Distillation
University of California, Berkeley, CA, Vol. 2, 1930, p. 443. Units,” IChemE. Symp. Ser., Vol. 56, 1979, pp. 3.1/15–3.1/35.
[33] Incropera, F.P., and DeWitt, D.P., Introduction to Heat Transfer, [56] Brown, R.N., Compressors: Selection and Sizing, 3rd ed., Gulf
3rd ed., John Wiley and Sons, New York, 1996, p. 413. Professional Publishing, Houston, TX, 2005.
[34] Petukhov, B.S., Advances in Heat Transfer, T.F. Irvine and J.P. [57] Reciprocating Compressors for Petroleum, Chemical and Gas
Hartnett, Eds., Vol. 6, Academic Press, New York, 1970. Industry Services, 5th ed., API Standard 618, American Petro-
[35] Gnielinski, V., “New Equations for Heat and Mass Transfer in leum Institute, Washington, DC, 2007.
Turbulent Pipe and Channel Flow,” Int. Chem. Eng., Vol. 16, [58] Hanlon, P., Compressor Handbook, McGraw-Hill, New York,
1976, pp. 359–368. 2001.
[36] Barletta, T., “Why Vacuum Unit Fired Heaters Coke,” Petroleum [59] Bloch, H.P., A Practical Guide to Compressor Technology,
Technology Quarterly, Autumn 2001. 2nd ed., John Wiley & Sons, Hoboken, NJ, 2006.
[37] Smith, J.M., Van Ness, H.C., and Abbott, M.M., Introduction to [60] Axial and Centrifugal Compressors and Expander-compressors
Chemical Engineering Thermodynamics, 7th ed., McGraw-Hill, for Petroleum, Chemical and Gas Industry Services (7th ed.),
New York, 2005. API Standard 617, American Petroleum Institute, Washington,
[38] Garg, A., “Good Heater Specifications Pay Off,” Chem. Eng., DC, 2002.
July 1988, pp. 77–80. [61] Rotary-Type Positive Displacement Compressors for Petroleum,
[39] Lobo, W.E., and Evans, J.E., “Heat Transfer in the Radi- Petrochemical and Natural Gas Industries, 4th ed., API Standard
ant Section of Petroleum Heaters,” Trans. Am. Inst. Chem. 619, American Petroleum Institute, Washington, DC, 2004.
Eng., Vol. 35, 1939, pp. 743–778, http://www.heaterdesign.com/ [62] Tsai, M.J., “Accounting for Dissolved Gases in Pump Design,”
LoboEvans1.htm. Chem. Eng., Vol. 89, 1982, pp. 65–69.
[40] Cross, A., “Evaluate Temperature Gradients in Fired Heaters,” [63] Chen, C.C., “Cope with Dissolved Gases in Pump Calculations,”
Chem. Eng. Prog., June 2002, pp. 42–46. Chem. Eng., Vol. 100, 1993, pp. 106–112.
[41] Mekler, L.A., and Fairall, R.S., “Evaluation of Radiant Heat [64] Wood, D.W., Hart, R.J., and Marra, E., “Pumping Liquids
Absorption Rates in Tubular Heaters,” Petroleum Refiner, Loaded with Dissolved Gas,” Chem. Eng., Vol. 70, 1998,
June/November/December 1952. pp. 110–114.

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14
Process Control and Instrumentation
L. Raman1 and N.S. Murthy1

14.1 Evolution of Process (highway addressable remote transducer) protocol with

Instrumentation/Measurements which range changes, diagnostics, and calibration are
In the last 40 years, the instrumentation field has gone remotely possible without removing the transmitter from
through a tremendous change in every aspect of measure- its location.
ment and control, with the earliest generation including Most of the cabling issues are resolved with field bus
pneumatic devices, next-generation electronic devices, smart technology. Using this technology, all plant signals can
devices, and the recent revolution of intelligent devices. In be routed to the control room with minimum number of
the late 1960s, pneumatic instruments were used for local cables. It also brings back the earlier pneumatic concept
measurement and control where control loops were closed of local field-level control. Transmitters and final control
in the field itself, making it a tedious job for the operator elements are fitted with an intelligent system that not
because jobs like changing the setpoint and tuning the only does signal conditioning, running control algorithms,
pneumatic controllers required manual intervention from sending output to final control elements, and accepting
the field. Later on, centralized control concepts were devel- feedback signals, but it also self-diagnoses itself and auto-
oped in which all pneumatic tubes were routed to a control matically reports any problem in the device. This leads to a
room through a systematically arranged pneumatic control paradigm shift in maintenance of instruments from preven-
panel with graphics. Further substantial improvements in tive- to issue-based maintenance. This helps in manpower
this field include electronic transmitters, 4- to 20-mA signals savings in maintenance and intelligently gives out all neces-
for measurement, and electronic-card-based controllers. sary information required for maintenance.
One remarkable invention was that of Zener barriers and Slowly we are seeing that the DCS and programmable
explosion-proof junction boxes, which helped in picking up logic controller (PLC) elated functionalities are merging
electronic signals even from/to hazardous areas. with personal computers. Already all major DCS vendors
With the advent of microprocessors, all of the elec- are providing their latest DCS in a Windows platform with
tronic controllers have transformed into microprocessor- “off-the-shelf” hardware. This is a major leap in the con-
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based smart controllers, with configurations that can be trol industry, which was earlier dominated by proprietary
customized for various control needs. This revolution has hardware and software. However, the control hardware still
greatly helped in the centralized control concept, with most remains proprietary, with operator consoles, graphics, and
of the industries revamping their control systems from other user-interface software having been moved to the lat-
pneumatic to electronic because of various advantages such est available open technology.
as changes in signal transmission distance, maintenance
cost, labor availability, and capital cost. All of the single- 14.2 Process Control—An Overview
loop controllers take I/Os (inputs/outputs) directly from the A refinery can be referred to as a manufacturing unit in
field through proper marshalling. All of these controllers which one or more feedstock is processed/distilled for con-
are monitored through a central supervisory system such verting it into several useful streams/products depending
as a Digital Virtual Address eXtension (VAX)-based system. upon the prevailing market conditions. A manufacturing unit
However, the control resides with single-loop controllers comprises several components such as distillation columns,
and operators can change setpoint values from consoles. reactors, vessels, heaters, heat exchangers, pumps, pipelines,
The concept of centralized control has led to the isolation valves, control valves, instruments, measurement
advent of distributed control systems (DCS), which helped devices, analyzers, etc. Process control enables harmonious
in the graphical distribution of functionalities. Single-loop operation of all of these components and helps them to func-
controllers have been replaced by card-level controllers in tion in unison within the safe limits, producing “high-value”
which I/Os are conditioned separately and fed into control- end products at the optimized/least operating cost. However,
lers for various actions on the basis of their configuration. to have an effective control of process, precise knowledge
This rendered a greater flexibility in control configuration of the following process variables is very essential.
revamp in a much quicker way as per the plant require- • Independent variable: This is a variable that is used for
ment. DCS vendors provide several control algorithms to making changes or manipulating the process for bring-
suit various applications; however, cabling, routing, and ing it to a certain specified state. It is used as an input to
marshalling of signal cables is considered to be the most the process. Examples of an independent variable include
laborious job in instrument erection, commissioning, and control valve opening, speed of a drive, etc., that can be
maintenance. Smart transmitters are introduced to make it independently changed. It is denoted as “MV” in process
possible to communicate with transmitters using a HART control language meaning, “manipulated variable.”
1
Reliance Industries, Ltd., Gujarat, India
355
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356 Petroleum Refining and Natural Gas Processing

• Dependent variable: This is a variable that changes as a • Cascade control: Also called “master-slave control,”
result of process manipulation for bringing the process cascade control is typically used when the primary
to a certain specific state. It is considered as an output (master) measurement and control is slower than
from the process. Examples of such variables include the secondary (slave) measurement and control. The
yields, throughput, velocity, heat flux, H2 consumption, inner (slave) loop always responds faster and is used
product quality, flooding in columns, energy consump- to control the outer (master) loop, which is compara-
tion, vibration, etc. tively slower in response. Typical examples include
• Disturbance variable: This is a variable that affects the controlling the heater coil outlet temperature (master)
process, but unlike an independent variable it cannot by controlling the pressure or flow (slave) of the fuel
be manipulated. It is also known as a feed-forward fired in the heater.
variable because it cannot be manipulated despite its • Adaptive control: Typically used in level control of a
significant effect on the process. Examples of these horizontal cylindrical vessel, where the volume change
variables include cooling water temperature, ambient per unit height varies drastically in the bottom and
air temperature, fouling in heat exchangers, upsets in upper sections of the vessel compared to the middle
downstream or upstream units, etc. section of the vessel. Adaptive level control uses dif-
• Controlled variable: This is a variable that must be ferent sets of tuning constants for extreme level condi-
regulated to a get a desired product in the process. tions as well as for normal level conditions. This helps
These are the variables that can be played with to drive by using buffer capacity available in the vessel without
the process and can be operated at a fixed setpoint or compromising the safety issues related to overflowing
between ranges of limits. Examples are flow, tempera- or emptying of the vessel.
ture, pressure, level, speed, heat duty, steam-to-fuel
ratio, gas-to-liquid ratio, stream properties, weighted 14.2.1.1 What Is Process Control?

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
average bed temperature in a reactor, optimum sever- The chemical process industry basically consists of unit
ity, etc. operations and processes. Various process parameters such
Typically in a process control environment, a devia- as pressure, level, flow, and temperature are controlled to
tion from set value or disturbance induces error. This error maintain key profit variables such as product quality, conver-
between the process value and set value has to occur first sion, and yields at the desired levels. Process control helps
for the controller to take action and close the deviation. in reducing the variability of the process, thereby minimiz-
However, in advanced model-based control, changes are ing the deviation from the desired operating conditions and
addressed in a feed-forward, predictive manner, and devia- improving the profitability. Process control is also important
tions are minimized. Types of process control are discussed to ensure that the plant is operating in the safe operating
in the following section. region.

14.2.1 Rudimentary Control 14.2.1.2 Elements of a Control Loop

These are basic, single-loop, feedback controls that work on Most basic process control systems consist of a control
the principle of minimizing error/deviation. The controls loop as shown in Figure 14.1 and have these four main
can simply be proportional + integral + derivative (PID) components [1]:
or any combination thereof depending on the operational 1. Primary measuring element
requirement. Extremely tight control can at times lead 2. Controller
to substantial disturbance in the downstream units. For 3. Final control element
example, tight control of level of a vessel that is pumping 4. Process
out product will end up passing on upstream disturbance Primary elements are devices that undergo some
in flow to the vessel to the respective downstream units. In changes in their properties with changes in process condi-
such cases, the buffer level of the vessel is to be utilized to tions that in turn are reflected as process measurement.
obtain smoothened flow downstream of the vessel so that Transducers are used for measuring process parameters.
downstream operations function smoothly. Transmitters/special transducers are normally used for
A few examples of rudimentary controls are measuring various process parameters such as flow, level,
• Simple ratio controls: These are used in controlling pressure, temperature, etc.
steam flow to the distillation column depending on A controller is a device that receives data from a
product draw-off rate. measuring instrument, compares those data against an

Figure 14.1—Typical process control loop.

AST-MNL58-11-0801-014.indd 356 3/12/13 2:31 PM

Chapter 14 n Process Control and Instrumentation 357

operating setpoint, and, if necessary, signals the control cost and improves the performance and reliability of the
element to take corrective action on the basis of the error valve. Valve stem travel feedback, actuator pressure sensor,
between setpoint and measurement. In normal feedback etc., are used to find the control valve performance. Smart
controllers, PID algorithms are mostly used for effective transmitters and control valve configurations, performance
control of the process parameters. monitoring, and troubleshooting are bundled as an “Asset
Final control elements are used to regulate the pro- Management System” in recent DCS systems.
cess so as to bring the measured process parameter to its In a typical refinery system, a wide array of transmit-
setpoint value. In most of the cases, pneumatic (i.e., air- ters, analyzers, and control valves are used in various units.
operated) diaphragm control valves, turbine speed, variable Some typical applications are listed in Tables 14.1 and 14.2.
frequency drives, fin-fan blade angle, damper openings,
etc. are the most common final control elements in process 14.2.1.4 Basic Control Schemes
control applications. Final control elements are used to The oldest strategy for control is to use a switch, giving
regulate the flow of material or energy into a system. simple on-off control. On-off control is also referred to
as two-position control. A typical on-off controller is “on”
14.2.1.3 Control Valves when the measurement is below the setpoint (SP) and the
Control valves are the main final control elements in most manipulated variable (MV) is at its maximum value; if the
of the chemical processing industries’ process control measurement is above the SP, the controller is “off” and
loops. Modern day control valves are fitted with smart the MV is at its minimum. Typical usage of on-off controls
transducers for tighter control. in manufacturing plants is for sump level control.
Normally control valves are selected based on type of In modulating control, the output of a controller can
fluids [2]; fluid properties such as temperature, viscosity, move through a range of values defined by an upper and
specific gravity, and flow capacity; pressures such as inlet, lower limit as the operating range. It is a smoother form of
outlet, and pressure drop at normal and shut-off condi- control than on-off control.
tions; maximum permissible noise levels; inlet and outlet In open-loop control, the final control element is nor-
pipe sizes; flange ratings; body material; speed of response mally operated manually to get a desired value. However,
(single acting or double-acting); and failure response such it needs constant attention to keep the MV at the desired
as air failure to close or air fail to open, etc. On the basis of value. In the case of a closed loop, the controller keeps the
this information, the user and valve manufacturer normally final control element moving to get the desired value as set
agree on valve size, valve body (butterfly, angle, double-port, in the setpoint. For closed-loop control, proper controller
etc.), valve plug guiding (cage style, port guided, etc.), valve selection and its tuning are important. A typical example
plug action (push down to close or push down to open), port of open-loop control is fin-fan outlet temperature control
size (full or restricted), valve trim materials, actuator size, using hand indicator controllers (HICs). In some units,
flow action (flow tends to open or close the valve), bonnet these HICs are converted to temperature indicator control-
style (normal, extended, bellow seal, etc.), corrosion and lers (TICs).
erosion preventive/resistive design of wetted parts and valve In a feedback control loop, the controlled variable is
leakage class, based on shut-off requirement. compared to the setpoint, and the difference/deviation/
The most commonly used control valve accessories are error acted on by the controller is calculated to move the
supply pressure regulators, analog I/P converters to control MV in a way to minimize the error.
the analog signal to pneumatic signal, and pneumatic posi- A feed-forward control system uses measurement of
tioners for better positioning of the stem to have accurate disturbance variables to position the MV and minimize any
control. Other optional items are solenoid valves, limit resulting deviation due to measurable process disturbance.
switches (to get feedback on the valve open/close condi- Typical examples are steam reboiler heat-duty controllers,
tions), volume booster for faster response on critical and measuring the temperature of the steam flow and process
bigger size valves, pneumatic lock-up device, etc. fluid temperature, and adjusting the steam flow for
Positioners are available in all of the three types such effective, consistent heat energy supply to the distillation
as normal, HART-based, and field-bus-based technologies column.
[3]. Field bus technologies enable the traditional PID con- In some cases, two or more inputs to the process are
trol at the valve or field transmitter level, thereby increasing used for controlling one process output. The inputs to the
product capabilities, and reducing wiring, which enables process are maintained in a fixed relationship.
automatic configuration and setup of the field instruments • The split range control configuration has only one mea-
and valve in a minimum amount of time, leading to the surement, such as receiver drum pressure (controlled
“control by wire” concept. A digital positioner comes with output), and more than one MV, such as nitrogen
embedded systems that use predefined instrument and supply pressure to pressurize the drum in case of lower
valve diagnostics and provides alerts for improper mount- pressure than the SP and depressurizing to flare in case
ings, electronics problems, control valve performance there is an excess pressure compared with the SP.
issues like gland tightness, drift in calibration, etc. It can • Normally this kind of control is used in a push-pull
be accessed remotely by a plant instrumentation team to type of control, such as heating and cooling, pressur-
troubleshoot, rectify, and reconfigure valves without much izing and depressurizing, filling and draining, etc.
effort, which enables predictive maintenance instead of Ratio control involves a controller that receives input
normal preventive and breakdown maintenance. Partial- from a flow measurement device on unregulated (wild)
stroke and signature tests help in identifying possible valve flow. The controller performs a ratio calculation and signals
sticking, pneumatic leaks in the actuator, packing-related
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
the appropriate setpoint to another controller that sets the
problems, etc. This substantially reduces maintenance flow of the second fluid so that the proper proportion of the
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358 Petroleum Refining and Natural Gas Processing

Table 14.1—Typical Refinery Measuring Instruments and Their Services

Instrument Instrument Subtype Units Equipment Service

Analyzer Combustible gas analyzer Crude, VGO, aromatics Fired heater Flue gas

Conductivity analyzer Alkylation, clean fuels, Reactors, headers BD, feed water, acid,
utilities steam

CO2 analyzer transmitter FCC, alkylation, Exchangers, reactors, Flue gas

polypropylene vessels

Density analyzer PRU, clean fuels, utilities, KOD, headers LPG, additive, fuel gas,
polypropylene, coker, diesel
tankfarm

Dew point analyzer Clean fuels, utilities Headers Instrument air

Dissolved O2 analyzer FCC, CPP Fired heaters, vessels Flue gas

Distillation analyzer Crude Pumps, headers Naphtha, kerosene,

diesel, HAGO

Flashpoint analyzer Crude, clean fuels, VGO, Headers, exchangers Diesel, kerosene, heavy
RTF kerosene

H2S analyzer Alkylation, sulfur, Merox, Absorber, drier, LPG, sour water, off gases
RTF regenerator

HC analyzer Clean fuels, utilities Header Steam

Humidity analyzer FCC Main column

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Infrared analyzer FCC, VGO, aromatics, RTF, Fired heater, header, Flue gases, diesel, alkylate
utilities exchanger

Moisture analyzer PRU, alkylation, PP, RTF, Drier, header Propylene, hydrogen,
aromatics nitrogen, net gas

O2 analyzer Crude, coker, clean fuels, Fired heater Flue gas

aromatics, CPP, PP

Oil in water analyzer Clean fuels Header Cooling water

pH analyzer Alkylation, crude, FCC, Headers Storm water

CPP, utilities
Pour point analyzer Crude Header
Reid vapor pressure Alkylation Tank Alkylate
analyzer
Residual Cl2 analyzer Utilities Tank Potable water
Sulfur analyzer Alkylation, clean fuels, Tank, drier, header LCO, diesel
ATU, RTF
Thermal conductivity Alkylation, VGO, Scrubber, compressor, Gas
analyzer aromatics separator
Viscosity analyzer RTF, utilities Tank, header Fuel
Water in oil analyzer Crude, utilities Pump Crude
Level Capacitance level Alkylation, aromatics Boiler —
Displacer level Crude, Merox, FCC, Desalter, KOD, pump Refrigerant, water oil
alkylation, utilities interface
Displacer level FF VGO Coalescer Kerosene, diesel
GWR level Entire refinery Vessels, reactors, HC, amine, fire water
strippers, separators
GWR level FF Entire refinery Vessels, reactors, HC, amine, fire water
strippers, separators, KOD
Magnetic float level Alkylation, PP Reactors Acid, emulsions

Copyright ASTM International

AST-MNL58-11-0801-014.indd 358 3/12/13 2:31 PM

Chapter 14 n Process Control and Instrumentation 359

Table 14.1—Typical Refinery Measuring Instruments and Their Services (Continued)

Instrument Instrument Subtype Units Equipment Service
Level CPP, utilities, coker, Pump, tank, splitter Caustic, phosphate,
Merox, crude nitrogen
Level FF Clean fuels, aromatics Stripper, KOD LCO, diesel
Microwave level Crude Desalter Crude, water
Nuclear level Crude, FCC, aromatics, Columns, reactors Catalysts, slurries-related

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
coker, PP services
Nuclear level FF Coker — —
Radar level FF PRU, alkylation, clean Reactors, columns Amine, slops, acid
fuels, utilities
Radar level Sulfur, CPP, RTF, utilities, Splitter, hopper, tank Catalyst, amine, fuel oil,
FCC, PRU diesel, reformate
Radar level Crude, RTF, Utilities Tanks Gasoline, propane,
propylene, naphtha, VR,
crude, antioxidant
Radar level RTF, ATU, SWS, crude Tanks, spheres Diesel, amine, VR,
propylene, gas, isobutane
Sonic level PP Pit Effluent
Flow Coriolis flow meter Crude, aromatics, PP, CPP Pumps, header Oil, fuel gas, isomar
Flow transmitter FCC, PRU, clean fuels, Header, compressor, fired Steam, nitrogen
aromatics, utilities, coker heater, pump
Flow transmitter FF PRU, clean fuels, utilities, Fractionators, heater, Water, steam, foam, HC
VGO, coker pumps
Indicating flow Coker, aromatics Fired heater, pump Steam, water
transmitter
Indicating flow Coker Fired heater Steam
transmitter FF
Magnetic flow Alkylation, CPP, utilities Reactors, mixers, tanks Water, acid
transmitter FF
Magnetic flow transmitter Alkylation, clean fuels, Tanks, headers Water
utilities
Rotameter flow Alkylation, RTF Drier, vessel Gas, inhibitor
transmitter
Turbine flow transmitter Utilities, ATU — —
Ultrasonic flow meter FF Sulfur, utilities Header Fuel oil
Ultrasonic flow Utilities, RTF, CPP, clean Tanks Fuel oil, diesel, gas,
Transmitter fuels, alkylation nitrogen
Vortex flow meter Utilities, sulfur Header Steam, saturated gas
Vortex flow meter FF Alkylation, CPP, RTF, Reactor, pump, tank, HC
utilities reboiler, ejector
Pressure DP transmitter Entire refinery Mixer, regenerator, Fuel gas, air, lube oil,
compressor, blower steam,
DP transmitter FF Entire refinery Pump, filter, fired heater, Kerosene, HCO, make-up
expander gas, naphtha
DP transmitter FF flow Entire refinery Fired heater, desalter, HC, nitrogen, fuel gas,
vessels, columns pilot gas, nitrogen, amine
DP transmitter FF level Entire refinery Stripper, KOD, separator, Amine, water, caustic, HC
tank
DP transmitter flow Entire refinery Fired heater, compressor, HC, comb air, nitrogen
blower, column
(Continued)
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360 Petroleum Refining and Natural Gas Processing

Table 14.1—Typical Refinery Measuring Instruments and Their Services (Continued)

Instrument Instrument Subtype Units Equipment Service
DP transmitter level Entire refinery Reactor, stripper, drier, Nitrogen, catalyst, HC,
absorber, filter lube oil, steam
DP transmitter weight PP Reactor Catalyst
Draft pressure transmitter CPP, utilities Fired heater, compressor
Pressure transmitter Entire refinery Fired heater, riser, Phosphate, refrigerant,
compressor, turbine, steam, HC, BFW
reboiler
Pressure transmitter FF Entire refinery Pump, separator, column, HC, lean gas, wash water,
fired heater nitrogen, hydrogen
Pressure transmitter level Utilities Sump Oily water
Temperature Temperature transmitter Entire refinery Fan, compressor, reactor, Air, HC, steam, nitrogen,
vessel, column flue gas, fuel gas
Temperature transmitter Entire refinery Fan, compressor, reactor, Air, HC, steam, nitrogen,
FF vessel, column flue gas, fuel gas
Corrosion Corrosion transmitter Alkylation, VGO, ATU, Condenser, stripper, BD —
coker, aromatics, utilities drum
Current Current transmitter Crude, FCC, PP Vessels, pumps —
Density Density transmitter FF Utilities — Fuel gas
Position Position transmitter FCC, PRU, clean fuels, Pumps, header —
CPP, PP
Power Power transmitter FCC, aromatics Compressor —
Speed Speed transmitter Crude, FCC, clean fuels, FD fan, ID fan —
CPP, VGO, PP
Stack monitor Stack gas monitor Clean fuels, VGO Fired heater —
Voltage Voltage transmitter Crude, PP Desalter, reactor —
Weight Weight transmitter PP — —
ATU, amine treating unit; BD, blow down; BFW, boiler feed water; Cl2, chlorine; CO2, carbon dioxide; CPP, captive power plant; FD, forced draft; FF,
foundation field bus; HAGO, heavy atmospheric gas oil; HC, hydrocarbon; HCO, heavy coker oil; H2S, hydrogen sulfide; KOD, knockout drum; LCO, light
cycle oil; LPG, liquefied petroleum gas; Merox, mercaptan oxidation; O2, oxygen; PP, polypropylene; PRU, propylene recovery unit; RTF, refinery tank farm;
SWS, sour water stripper; VGO, vacuum gas oil; VR, vacuum residue

Table 14.2—Typical Control Valve in Refinery Service

Type of Control Valve Units Equipment Service

Angle control valve Coker, FCC, PRU, LCO cracker Pumps, naphtha splitter, Wash water, naphtha, LCO,
stripper diesel

Ball control valve Crude Headers, exchangers, splitters, Crude, isomerate

tanks

Butterfly control valve Crude, acid regenerator Fired heaters, pumps, KODs Vapors, hydrocarbon

Control valve Crude, FCC, PRU, VGOHT, coker Exchangers, pumps, fired Crude, caustic, BFW, sour
heaters, columns water, DM water, lean amine,
hydrocarbon

Damper control valve Crude, HNHT, LCO cracker, Fired heater Combustion air, flue gases
VGO HT

FV control valve linear field-bus Platformer, VGO HT, ATU, PRU — Lean amine, phenolic water,
FF control valve hydrocarbon

FV control valve linear control FCC, VGO HT — Diesel, naphtha, VR, LCGO,
valve wash water
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Copyright ASTM International

AST-MNL58-11-0801-014.indd 360 3/12/13 2:31 PM

Chapter 14 n Process Control and Instrumentation 361

Table 14.2—Typical Control Valve in Refinery Service (Continued)

Type of Control Valve Units Equipment Service

FV control valve quarter turn FCC, ATU Exchangers, columns Hydrocarbon

field-bus FF control valve

FV control valve quarter turn TGTU, sulfur, FCC Exchanger, reboiler, column Acid gas, lean amine, cycle oil

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
control valve

FV control valve severe service Alkylation Pumps, compressors Hydrocarbon

control valve

FV damper valve control valve — FD fan Comb air

Gate control valve Crude, alkylation, coker, Condenser Steam

platformer

HV control valve angle control valve DHDS Absorber, columns Sour water, amine

HV control valve angle field-bus DHDS Stripper —

FF control valve

HV control valve field-bus FF Platformer Header Gas

control valve

HV control valve butterfly VGO HT KOD Flare gas

control valve

HV control valve globe control valve FCC, PP Headers, vessels Vents, steam

HV control valve linear field-bus Platformer Fired heater Steam

FF control valve

HV control valve linear control valve — Scrubber, absorber Amine

HV control valve severe service Platformer, FCC Compressor, reboiler —

field-bus FF control valve

HV control valve severe service VHO HT Flash drum Hydrocarbon

control valve

HV damper control valve Clean fuels Condenser, fans Hydrocarbon

HV damper general Coker Fired heater Comb air

HV double acting pneumatic FCC Separator —

valve control valve

HV future control valve CFP Heater Oil

HV isolating ball valve control valve PP Pump, column Hydrocarbon

HV manual regulating valve LCO hydrocracker Separator LCO

control valve

HV piston-operated valve control Acid regeneration Nozzles, separator, boilers Propane, BFW, nitrogen
valve

HV single-acting pneumatic valve — Header BFW

control valve

Actuating on/off valve/control valve PP Headers, tank, vessels Nitrogen, gas, slurries

LV control valve ball control valve — Vessels Steam

LV piston-operated valve control FCC Header VGO

valve

LV single-acting pneumatic valve Coker Vessels Amine

control valve

MOV — Compressor, pump, tank Alkylate, gas, LCO, VGO,

steam, LK

TV control valve ball control valve — Header Steam

TV control valve control valve — Header Steam

TV piston-operated valve control FCC Filter Catalyst

valve
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362 Petroleum Refining and Natural Gas Processing

Table 14.2—Typical Control Valve in Refinery Service (Continued)

Type of Control Valve Units Equipment Service

Double-acting pneumatic valve FCC Header Slurry oil

control valve

XV actuating on/off valve control Crude, platformer, DHDS, LCO Fired heater Fuel gas, fuel oil, pilot gas
valve cracker

XV double-acting pneumatic Coker Pumps, vessels Debut feed

valve control valve

XV isolating valve ball control Coker, DHDS Pumps, headers Cooling water, flushing oil,
valve off gas

XV isolating valve butterfly Coker, DHDS Fired heater, filter, Fuel gas, pilot gas, naphtha
control valve fractionators, pump

XV piston-operated valve control PRU, FCC, VGO HT Pump, reboiler, reactor, Ammonia, wash water,
valve fractionators hydrocarbon

XV power actuated valve block CFP, ATU Pumps, KOD Slop oil
control valve
CFP, clean fuel project; DHDS, diesel hydrodesulfurization; HT, hydrotreater; TGTU, tail gas treating unit. VGOHT, vacuum gas oil hydrotreating; HNHT,
heavy naphtha hydrotreating; LCGO, light coker gas oil; FV, flow control valve; HV, hand valve; FF, field-bus enabled valve; LV, level control valve; TV,
temperature control valve; MOV, motor operated valve; XV, shut-off valve

second fluid can be added. In refineries, ratio controls are cascade, ratio, lead-lag, etc., work on error between actual
widely used right from the crude preheating ratio, desalter plant measurement and operator setpoint. As long as there
crude and water ratio, and in the final product blending is an error, these regulatory controllers move the final
ratio for making premium-grade fuels with additives for control element to achieve the setpoint on the basis of the
performance boosting. controller mode (PID) and the entered tuning constants.
Cascade control is a control system in which a secondary The next level of advanced control comes into existence
(slave having fast dynamic response) control loop is set up to through direct digital control (DDC) and supervisory set-
control a variable that is a major source of load disturbance point control (SSC). Both of these are related to an external
for the primary (master having comparatively slow dynamic computer program other than the regulatory PID control-
response) control loop. The controller of the primary loop lers. DDC has the capability to set the valve output, thus
determines the setpoint of the summing controller in the bypassing the regulatory PID loop. SSC has the capability
secondary loop. Cascade control is used when high perfor- to write the setpoint to underlying PID controller.
mance is needed during frequent random disturbances. It Model predictive control (MPC) is one of the advanced
allows faster secondary controller to handle disturbances in process control (APC) variants that has the capability of
the secondary loop. Typical examples are distillation column providing the target for the regulatory controller based on
top-tray temperature control using reflux flow and reflux its prediction capability from the underlying plant empirical
drum-level control using draw-off flow. model derived from the plant step test. Modern-day MPC
Lead-lag control is important in fired heaters, steam deals with plant constraints and optimization on the basis
boilers, and hydrogen reformers. When heat input to the of a linear-programming (LP)-based cost optimizer, giving
heater is varied, sufficient air should always be available for the best operator output on a 24 × 7 basis. MPC knows
complete combustion of fuel fired. interactions among all of the “variables” from the output
To increase the heater outlet temperature, the main to the input relation model derived from the plant step test,
temperature controller increases its output, which in turn can “predict” the effect of one variable on others (interac-
increases the air flow to the heater first using a high selection), and takes control actions accordingly. The APC and
tor switch (HSS) between temperature controller output MPC terms are used interchangeably in the process control
and fuel flow controller output before increasing the fuel domain.
to the heater. This increase of fuel flow controller output With APC, the unit operations are directly controlled
is governed by a low signal selector between temperature in terms of profit variables such as separation quality,
controller output and air flow controller output. conversion, yield, etc., instead of inferred variables such as
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Combustion air leads fuel in the case of an increase in pressure, temperature, flow, level, etc. Also, more consistent
firing requirement and lags fuel in the case of a decrease in controls and surety of the respecting constraint observation
firing requirement; hence, it is called lead-lag control. It is result in the plant operating much closer to the real plant
possible only in the case of balanced draft heaters in which constraints as compared with the normal regulatory con-
air intake can be finely controlled and measured. trollers and manual operation by the operator.

14.2.2 Model Predictive Control 14.2.2.1 APC Terminologies

Basic regulatory controls like flow, temperature, pressure There are two major types of variables in a controller. In a
and level controls, and advanced regulatory controls like given process that is to be controlled, independent variables
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Chapter 14 n Process Control and Instrumentation 363

are input to the process and the dependent variables are are moved such that the net response of changes in the MVs
output from the process [4]. matches with the desired change in the CV values. Thus,
The dependent variables are also known as controlled more than one MV may be moved to satisfy the CV values.
variables (CVs). These are the variables for which targets are The controller follows certain rules while coming up with
defined, and the controller tries to maintain these variables the required MV moves.
to their targeted levels. The dynamic behavior of the CVs can • Rate of change of MV moves (as defined by the control
be described totally in terms of specific independent vari- engineer)
able changes over time. These might include product stream • MV limits (as defined by the control engineer)
properties, temperatures, pressures, differential pressures, • Changes in CV values as a result of MV moves (no con-
valve positions, or other outputs from the process. straints are violated)
CVs are normally maintained at a constant value or If all of the above conditions are satisfied, the control-
between high and low limits, which allows the controller ler comes up with the best solution. If any of the above
more room to optimize the process. is likely to be violated, the controller considers that as an
An independent variable is a causal variable for which additional constraint and recalculates the MV moves. It
the value is not affected in any way by any other variable in tries to maintain all linear CVs to their target values and
the process and that, when changed, causes a correspond- all constraints within limits. The moment it is not able to
ing change in the process. Independent variables are fur- come up with the best solution it calculates the next-best
ther classified as MVs and disturbance variables (DVs) or solution based on the priorities set by the control engineer.
feed-forward variables (FFVs). The controller also retains information of some of the
MVs immediate past runs and compares the predictions with the
MVs are the independent variables that are moved (i.e., actual responses. On the basis of the differences observed,
manipulated) by the controller to control the process. Two it generates “bias” factors that in turn are used to fine-tune
main criteria for qualifying a variable as an MV are the next outputs from the controller. This solution may be
1. It should affect the CVs. a MV move away from the ideal resting value (IRV), an
2. It can be set and manipulated by the controller. offset in the linear CV, or to “give up” on less important con-
Examples of MVs are SPs to regulatory controllers and straints. To know the relative importance of constraints, all
valve positions. constants are given ranks that are assigned by the control
FFVs engineer. Also, all CVs and MVs have a weightage factor
FFVs are the independent variables that have a signifi- assigned to them. This helps the controller in knowing the
cant effect on the process but still cannot be manipulated control hierarchy.
by the controller. These may include ambient temperature,
feed composition, and cooling water supply temperature. 14.2.2.4 Benefits of APC
Some of the benefits of APC are listed below [5].
14.2.2.2 Steps in Developing an APC • The given unit operation/unit process is directly con-
Controller trolled in terms of profit variables such as separation
• Functional design study (this includes a detailed study quality, conversion, yield, etc., instead of inferred vari-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

of process and determination of project cost and ables such as temperature, pressure, level, flow, etc.
benefits) • Improved and consistent controls and accurate obser-
• Preliminary design vation of the constraints lead to plant operation being
• Review of process objectives much closer to the real constraints as compared
• Controller scope definition with manual operation. This leads to benefits such
• Preliminary process test as throughput increase. APC considers the effects of
• Control specification report changes on all CVs and finds the best overall solution.
• Plant step testing It reduces variations in process parameters.
• Detailed design and simulation • The control action is objective and is an optimal deci-
• Develop dynamic models sion for a given change/situation. This is also ensured
• Develop inferential property estimators around the clock. Along with confidence of tighter,
• Offline controller simulation and tuning timely control, it leads to enhanced profitability in
• Controller model review terms of improved/stable conversions, improved yields,
• Integration and commissioning reduced energy/utility consumption, etc.
• Closed-loop commissioning • Smooth and consistent control operation and less manu-
• Final project documentation al interference/manpower is required in the normal oper-
• Develop inferential property estimators ation. The operator need not continuously monitor each
• Postcommissioning sustained performance and every process parameter and take manual action.
• Controller monitoring • Because the equipment constraints are always observed,
• Maintain ongoing training efforts it leads to higher equipment service factors. The con-
straints can be prioritized per operations philosophy
14.2.2.3 Functioning of an APC Controller and safety considerations.
Through the step testing and model identification package, • Tighter controls reduce the deviation in product qual-
all relationships between the CVs and MVs are obtained in ity, thus keeping the product quality parameters at the
the form of models. Once models are known, the controller desired values. Incidents of product off-spec and qual-
can predict the CV values for given changes in the MVs or ity giveaway can be avoided and hence prevent any loss
vice versa. To achieve the desired values of CVs, the MVs of opportunity.
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364 Petroleum Refining and Natural Gas Processing

14.2.3 Benchmark Information 14.3 Quality Measuring Instruments

In the hydrocarbon business, the refining sector in particu- Maintaining consistent product quality and minimizing the
lar is challenged with many constraints relating to safety quality giveaway are the main tasks of all manufacturing
and environment, customer demands on cleaner products, industries. However, conventional frequent sample col-
need for sweating the assets to get the best from every lection, analysis of the sample in the laboratory, and then
drop of oil, spiraling energy costs, varying crude qual- taking corrective actions is not a sufficient way to control
ity, etc. Understanding the crude oil is itself an art with the modern-day refining processes that are highly dynamic
complexities of issues such as compatibility; presence of and economically demanding. Improvements in the sensor
corrosive species such as naphthenic acids, salts, sulfur, technology and availability of digital techniques based on
and chlorides; increasing heaviness as seen in drop in API; signal processing have led to highly sophisticated, custom-
impediments in transportation in a few cases because of izable, ready-to-use online process analyzers to overcome
higher viscosity and pour point; and an ingress of undesired the earlier conventional analog-type analyzers. Modern-day
elements such as metals, solids, chemicals, additives, etc. analyzers are highly configurable for satisfying various
Refiners pay immense attention into feedstock manage- needs because they intelligently diagnose routine samples
ment so as to ensure reliability of the processing units while to minimize maintenance efforts.
endeavoring to maximize and sustain profitability. Online analyzers are used for continuous monitoring
Process control and optimization play a pivotal role of the feed, intermediate, and final product qualities. These
in achieving the desired level of performance under such analyzer values are further integrated with the process con-
variances faced daily by refining industries. In fact, trol systems to give feedback and control the process in real
to get the best from APC/optimization strategies, it is time. Typical applications of the online analyzers are given
mandatory that basic instrumentation (i.e., measuring below.
elements, control valves, online analyzers, etc.) is well • Feed/product stream quality monitoring such as sulfur
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

within the operable range with a desired accuracy of content, density, endpoint, flash point, pour point,
measurements. Further, the process automation team, humidity, dew point, etc.
multidisciplinary in nature (drawn from domain experts • Parameters pertaining to environmental regulations
of operations, process engineering, instrumentation and monitoring (i.e., oxygen, carbon monoxide, oxides of
computing capabilities), has full-time professionals for nitrogen and sulfur, opacity, etc.) in heater stack flue
advanced control/optimizer upkeep. Benchmarking of gas, etc.
the process control application facilitates raising the • Water quality parameters such as pH, silica, conductiv-
performance bar of a refinery. Some of the elements/key ity, dissolved oxygen, chlorine, etc.
parameters used in the benchmarking of process control • Effluent monitoring parameters such as oil in water,
are given below. Each refiner can pick up the appropriate total suspended solids, total organic content, etc.
element depending on their business environment and • Gas chromatographs are widely used for quality moni-
work toward excellence. toring and control of various hydrocarbon streams.
• Uptime factor of control strategies In addition to these online “wet” analyzers, near infra-
• Production plan versus actual closure red (NIR)-spectroscopy-based “noncontact”-type analyzers
• Number of process automation full-time employees per are available for property predictions such as research
process unit to maintain the strategies octane number (RON), cetane number, density, and distilla-
• Benefits from APC/optimizer in cents per barrel of feed tion of petroleum products. It is mainly used in the product
to the unit blending loop to control various component streams for
• Standard deviation of critical controlled process vari- making a particular blend of product conforming to quality
ables (yield, quality, or energy use) objectives dictated by the blend optimizer.
• Sigma average error and time taken to reach steady
state from a disturbance 14.3.1 Introduction to NIR Spectroscopy
• Tracking of out-of-service controllers on a daily basis Infrared spectroscopy is one of the most important analyti-
• Mean time to correct controller from off to on cal techniques available today. One of the great advantages
• Time to implement fully functional APC/optimizers in of infrared spectroscopy is that virtually any sample in any
processing unit state can be analyzed. Infrared spectrometers have been
• Validation of SP given by APC/optimizer strategies commercially available since the 1940s. At that time, the
through offline models instruments relied on prisms to act as dispersive elements,
• System of embedding “live” business drivers into APC/ but later diffraction gratings were introduced into disper-
optimizer strategies sive machines. However, the most significant advances in
• Bias update frequency in inferential prediction infrared spectroscopy have come about as a result of the
• Use of adaptive control introduction of Fourier-transform spectrometers. This type
• Time to steady state between feed changes in a given of instrument uses an interferometer and exploits the well-
unit established mathematical process of Fourier transforma-
• Delta error in inferential prediction with laboratory tion. Fourier-transform infrared (FTIR) spectroscopy has
referee method dramatically improved the quality of infrared spectra and
• Early event detection capability minimized the time required to obtain data.
• 24 × 7 support to manufacturing onsite or through Infrared spectroscopy is a technique based on the
remote methods vibrations of the atoms of a molecule. An infrared spec-
• System of incorporating innovations in control trum is commonly obtained by passing infrared radia-
strategies tion through a sample and determining what fraction of
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Chapter 14 n Process Control and Instrumentation 365

the incident radiation is absorbed at a particular energy. olefins, naphthenes, and aromatics) contents are more likely
The energy at which any peak in an absorption spectrum to be predictable (especially octane number, cetane number,
appears corresponds to the frequency of vibration of a part benzene, cloud point, or aromatic content) than those linked
of the sample molecule. with C-H, N-H, or O-H bonds, such as sulfur, which is pres-
The presentation of spectral regions may be in terms ent in small amounts.
of wavelength (λ) as nanometers (1 nm = 10−9 m). Another The improvement in computer technology associated
unit that is widely used in infrared spectroscopy is the wave with spectroscopy has led to the expansion of quantita-
number (ν) in cm−1. This is the number of waves in a length tive infrared spectroscopy. The application of statistical
of 1 cm and is given by ν = 1/λ. This unit has the advantage methods to the analysis of experimental data is known
of being linear with energy. as chemometrics. The most commonly used analytical
The infrared spectrum can be divided into three main methods in infrared spectroscopy are partial least-squares
regions: (PLS) and principal component regression (PCR). PLS is a
1. Far-infrared (<400 cm−1) least-squares method that involves matrix operations. The
2. Mid-infrared (4000–400 cm−1) PLS method is very useful in investigating very complex
3. Near-infrared (13,000–4000 cm−1) mixtures such as petroleum products. This method is used
A typical gasoline NIR spectrum is shown in Figure to build a model as a function of the variance in the spectral
14.2. data set.
The x-axis shows the wavelength λ (nm) and the y-axis
represents the absorbance in fraction. It is to be noted that 14.3.1.2 NIR Model Implementation
the absorbance of the sample if irradiated with NIR varies The implementation of a model occurs in three steps [6]:
at different wavelengths. This is because the absorbance of 1. Model building (i.e., calibration)
different species (molecules) in the sample gets pronounced 2. Model validation
at different wavelengths. The figure shows the different 3. Online prediction.
species and their active wavelength regimes for a typical Model building involves
gasoline spectrum. • Calibration set specification to identify the properties
The quantitative analysis method is used to predict the and ranges for the model
properties of various samples rather than analyzing indi- • Data collection for calibration (laboratory primary
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

vidual spectra. analysis and the corresponding NIR spectra for each
sample)
14.3.1.1 How Does NIR Work? • Model building using a multivariate calibration tech-
Hydrocarbon molecules contained in refinery streams nique
absorb NIR radiation because of C-H bond “movements.” • Preliminary model validation using the same software
This translates into a product “finger print” that can be It is very important to note that the models are highly
recognized by means of chemometric techniques. The absor- specific to refinery, the type of processes used, crude diet,
bance spectra can therefore be translated into performance product requirements, etc. Model validation is done by
properties. Those linked to PIONA (paraffins, isoparaffins, comparing the predicted values with the corresponding

Figure 14.2—Typical gasoline NIR spectra [6].

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366 Petroleum Refining and Natural Gas Processing

laboratory primary data. A statistical quality control chart per operator, disabled alarms, unacknowledged alarms,
for each property is prepared and validated. nuisance alarms, etc., which allows the operations and
Online model prediction is done by instrumentation and control team to prioritize and focus
• Loading the model into an offline laboratory system on major problems, thereby reducing the occurrence of the
and online system in the field. process upset alarms. A domain-specific alarm manage-
• Configuring the factors, outlier limits, and ranges. ment system with an expert system to analyze and diag-
• Online predictions are continuously monitored through nose the root cause of the problem is the next step toward
a plant historian. healthy alarm management. Alarm rationalization exercises
• Periodic laboratory analysis for verification of model are being done in some operating units.
performance.
14.5 Poor Process Design Leading to
14.3.2 NIR Applications Control Problems
The typical NIR applications for the refinery include the During a recent grass-root start-up of a manufacturing
prediction of the following: unit, many issues arose because of poor process design,
• Gasoline improper instrument selection, which led to different con-
• RON trol issues. Some of the major implications were as follows:
• Motor octane number (MON) • Complete process condition/parameter information
• Vapor pressure not available and/or misunderstood by the design and
• Distillation vendor engineers, during selection of the instruments
• Diesel for various services, leading to failure in the opera-
• Cetane number tion of the instrument for that particular service (e.g.,
• Cetane index dielectic constant of the liquid hydrocarbon is neces-
sary for measurement using radar level transmitters).
14.4 Advancements in Instrumentation Also, clean and dirty services are to be mentioned at
and Process Controls early stages for proper selection of the instrument.
14.4.1 Distributed Control System • Most of the modern control valves are selected with
A distributed control system (DCS) in a modern refinery antiflashing/anticavitation trim instead of conventional
helps in plant-wide automation. DCS is functionally and trim. This kind of selection without necessary study
geographically distributed with redundant control hard- leads to chocking problem in the trim, subsequently
ware. The modular nature of the hardware and software calling for more maintenance.
provides easy expandability of the various DCS functional- • Only field-proven technologies should be selected
ities to new units in a seamless manner. for critical services, otherwise any plant emergency/
In a typical refinery, all plant measurements signals shutdown leading to the failure of the new technology
are terminated at plant interface buildings (PIBs), which instruments proves costlier.
contain all necessary signal conditioning units and control • All emergency trip signals should be hardwired instead
processors for executing more than 100 different software of serial link data communication, which causes a
blocks for various functions such as analog and digital delay in tripping of the equipment and is less reliable.
inputs, control algorithms, calculations, advanced controls, • Wrong level transmitter tapping during the design,
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

and analog and digital outputs. All analog and digital out- causing improper level measurement in the fraction-
put processes from control processors and other similar ator pan tray, which causes the level control to be very
modules such as emergency shutdown systems are again difficult during a disturbance.
routed to final control elements in the field. In short, all • Inadequate number of trays between two pan trays
data acquisition and control functions are done at the PIB in the main fractionator leading to jet flooding,
level. Signals from PIBs are routed to a refinery control cen- which causes a disturbance in the column differential
ter for monitoring and control through operator consoles. pressure, making it difficult to control the column
Other than normal data acquisition and control func- profile.
tions, a DCS also provides a platform for real-time data- • Hydrogen blanketing of the feed surge drum causing
bases such as InfoPlus.21 for collecting periodic plant data more hydrogen solubility in the feed. Because of this,
for maintaining history as well as performance calculation controlling hydrogen flow to the reactor becomes very
and monitoring of the units. A DCS also forms the basis for difficult.
implementation of APC such as multivariable predictive
controllers and real-time optimizers. 14.6 Reliability Assurance in Process
Control and Instrumentation
14.4.2 Process Alarm Management Reliability-focused culture is catching up in every manu-
In today’s advanced control systems, one can define vari- facturing business enterprise. The problems related to poor
ous alarms on I/O and various control blocks with different reliability can range from unplanned interruptions/shut-
alarm types such as high, low, high-high, low-low, rate of downs, spurious trips, product becoming off-spec, excessive
change, deviation, etc. These kinds of messages entirely energy consumption, underutilization of assets, overfill or
flood the operator station if not properly configured and are underfill in dispatches, increased lifecycle cost, or any com-
likely to divert the attention of the operators. Recently, most bination of these factors. Reliability implies availability of
of the control system vendors have come up with alarm the instrument for the intended purpose and precision of
management software that can detect the total number of the measurement/control thereof close to the desired accu-
repetitive alarms and the number of I/O bad alarms, alarms racy. Design for reliability is gaining importance because
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Chapter 14 n Process Control and Instrumentation 367

lessons learned from past incidents/experiences show the is another progression that facilitates a holistic view of the
need for improvement in equipment selection, ensuring process so that reliability can be enhanced.
operation within the accepted window and correct man- Nevertheless, new challenges to process reliability have
ning. While aspects such as personal skill and level of moti- also cropped up in the form of spurious trips, communi-
vation are critical to reliability, they are outside the scope cation errors, control board component failures, loss of
of this chapter. Other issues that enhance/provide assured power to the solenoid valve, and so on. For example, in the
reliability are dealt with in this section. old pneumatic system, open loops seldom had any alarms
Concepts such as quality function deployment (QFD), and closed-loop alarms were minimal. A typical crude unit
failure modes and effect analysis (FMEA), 5 Whys, etc., used to have approximately 20 audiovisual alarms. With the
are typically deployed by refiners to improve the reliability advent of the DCS, the number of alarms can be three per
factor. Pacesetter refiners are able to achieve a continuous open loop (including the rate of change of process value
run length of 9 or more years in all major processing areas as a deviation alarm) and nine per closed loop. In other
such as crude distillation, fluid catalytic cracking, coker, words, a crude unit with 250 or more open-loop indications
platformer, etc. In other words, the process instrumenta- and 60 or more closed loops can have as many as 1200 or
tion and control system in pacesetting organizations must more alarms, which has made it necessary for reliability,
be robust enough with the necessary built-in redundancy to process, control, and operations engineer teams to classify
ensure safe and sustained operation. the alarm into “must” and “good-to-have” categories. Mod-
To elaborate on the above concepts, the process of ern refineries undertake “alarm rationalization” tasks and
coker furnace operation is taken as an example. This optimize the number of alarms for effective monitoring. It
process involves heating of feed vacuum residue from is a good practice to review the last 24 h of alarms daily to
600 °F at the coker fractionator bottom to 930 °F at the take appropriate corrective/proactive actions.
coker furnace outlet. The furnace heat duty is supplied by On many occasions it is seen that protection of equip-
coil outlet temperature control, which manipulates the ment overrides the importance of the whole process in
amount of fuel fired. There is a lead-lag system to control which the specific equipment is just a part. To ensure equip-
fuel fired in the heater and an air preheater for preheating ment reliability, the vendor provides several trip logics to
combustion air and balanced draft operation. The furnace prevent it from operating outside of the machine-specific
outlet temperature is well under control within 1 ºC. In window. However, in reality it is witnessed that such trips
other words, the process looks robust; however, the run have indeed resulted in process upsets/plant shutdown
length of heater coils (i.e., between two decoking opera- because these have been provided in isolation. For example,
tions, which is critical to coker management because it it is advisable to operate any pump or compressor within
affects refining margin) varies substantially from 120 to its turndown limits, and to prevent it from being operated
180 days. It shows that a few more operational controls below turndown, recycle loops are provided by equipment
are to be put in place, such as uniformity of heat flux vendors. Inadvertent/malfunctioning of opening of these
across the length of the furnace, minimizing cracking spillbacks could result in tripping of heaters or loss of level/
within the heater coils, feed quality management, etc. pressure in downstream units. Hence, it is imperative that
With the coker unit increasing the refining margin by the process is looked at in totality to ensure that cascaded
approximately $250–400/ton of feed, any downtime of failures do not occur.
the coker furnace for decoking (by pigging, spalling, or There are instances that result in spurious tripping
steam/air decoking) will erode the margins. In short, this of the plant, especially when single instruments are not
is a clear case of higher requirements from the customer backed up for data integrity. To overcome this, the concept
(business group is considered as an internal customer in of “two-out-of-three” (2oo3) logic was brought in, with three
this case) demanding additional input variables (vital Xs) independent field measuring devices to read the process
to be culled out and controlled. conditions. Only when two of three such instruments read
Understanding each of the business-critical processes a deviation/error does the process abort and take to a safe
in a manufacturing setup and getting deeper into it to shutdown position. Modern programmable logic controllers
improve and sustain profitability are increasingly becom- (operating at an every few millisecond span time) have the
ing imperative in today’s competitive environment. From ability to display the alarm initially, which helps in failure
the erstwhile pneumatic system supported by audiovisual diagnosis.
alarm, the instrumentation has migrated to an intelligent, Solenoid valve burnout is a common phenomenon in
self-diagnostic, and auto-tuning new-generation system. refineries. Normally solenoid valves are energized, and any
Digital magic has made immense advancements and pos- loss of power would result in activation of shutdown logic,
sibilities in process control applications. Newer control leading to unit operation terminating at a respective safe
algorithms such as nonlinear-level control, dead band, and position. Conversion from “de-energized to trip” to “ener-
adaptive controls are used, especially when a process is gized to trip” is one such possibility to minimize/mitigate
required to operate at different modes, varying regimes, or spurious trips.
both for equipment performance curves. Smart controls, Human errors arising from lack of experience/training
which take inputs from past heuristics and expert systems, have been the cause for some of the reliability issues seen
fuzzy logics, inferential controls, global optimizer, etc., have in operating units. Use of training simulators to understand
been made feasible in recent times. Seamless integration the shutdown sequences and process intricacies would help
of online/real-time applications and unit operations with to prevent such failures. In most cases it is even preferred to
offline processes (e.g., planning, scheduling, product test- provide a few seconds delay in tripping if the process/equip-
ing and certification, condition monitoring, and a model-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
ment allows such. Attending to boiler drum (three-element
based approach for providing a “best operating window,”) controller: steam flow, feed water flow, drum level) level
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368 Petroleum Refining and Natural Gas Processing

is a classical example for many spurious trips at several time control applications. Molecular-level analysis, using
manufacturing sites. A systematic study on “instrumented physical and inferential soft sensors, will dynamically
protective function” by a multidisciplinary team (process, optimize and allocate various plant loads. Refineries will
operation, and instrument) can also help to eliminate spuri- be able to swing their production to operate at various
ous trips by evaluating process dynamics at each phase of demanding market conditions in a much faster and con-
operation (i.e., starting, steady state, increasing/reducing trolled way.
throughput, and plant severity, etc.).
In summary, in a complex refinery there are over 14.8 Process Control Case Studies
110,000 opportunities for defects/failures from a well 14.8.1 Control of Crude Preheat Exchange
designed and operated process control and instrumenta- Trains
tion system. The refinery management deploys Six Sigma 14.8.1.1 Introduction
methodology to deliver highly safe and reliable operation. Preheat train exchangers form an important part of
Although the efforts have raised the performance level to a any crude unit because they are the backbone of heat
Sigma level of 5.2 in totality, world-class reliability is being integration in this unit of a refinery. Total heat require-
relentlessly pursued to attain still higher levels. ment in the crude furnace can be offloaded if the preheat
All process control and instrumentation is undergoing is optimum so the unit can be run efficiently with higher
revamping to include the best of various emerging tech- margins of throughput. Figure 14.3 depicts a typical crude
nologies such as smart sensors, wireless sensors, model-free unit preheat train related control configuration.
adaptive control, miniature MPCs, and early event detec- The crude received at the battery limit of the crude
tion systems based on plant operating data. distiller unit must be preheated from ambient temperature
to the temperature required for an efficient desalting opera-
14.7 Envisioning the Refinery of the tion. This preheating also helps to maximize heat recovery
Future from the crude column outlet streams.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

There are several ways to visualize the “Refinery of the The inlet crude stream is split into two streams with
future,” which is gaining importance with hardened crude one stream entering on the shell side of the S01 heat
oil prices coupled with the fear of “oil-peaking.” For exchanger and other stream entering on the shell side of the
example, the future refinery will have its own inner ability S02 heat exchanger. The crude is preheated in exchangers
to evaluate and select the crude within a couple of hours S01 and S02 by circulating naphtha, which is drawn from
to buy ahead of competition and enjoy the initial market the crude column naphtha accumulator tray through the
discounts. Refiners are stretching their limits to maximize tube side of S01 and S02. A flow indicator controller (FIC)
the profitability (measured as gross/net margins in dollars controls the naphtha flow to exchangers S01 and S02. The
per barrel) every single day, and yet the mean time between naphtha outlet stream from these exchangers is routed
turnarounds must be as maximal as possible (say 9 or back to the crude column top tray. The flow of naphtha
more years). There are people-related issues in terms of through these exchangers is always maximized to enhance
talent retention, nurturing innovations, cycle time reduc- heat recovery.
tion between idea and implementation, etc. However, the Providing a split range ratio controller governs opening
refinery of the future relating only to process control and of control valves and ensures equal distribution. One of the
optimization has been taken up further. control valves will be wide open (of the exchanger train,
Communications technology has matured, and with which exerts more pressure drop) and the other’s opening
increased bandwidth over wireless it is possible that the will be adjusted to maintain the same flow as that of the
optical fibers and hardcore cables running between the other train.
plant and control center could be no longer needed. Process
intensification and nanotechnology have made strides into 14.8.1.2 Control Scheme for Pump around
every manufacturing business, and it is feasible that the Heat Exchangers
current system of producing different products from crude The controls for the tube side of the S01 and S02 exchanger
will pave the way to choosing/producing any product and outlets are obtained by throttling of control valves FV1
converting the entire crude into that singular product. The and FV2, respectively, by feedback controllers. At the same
role of services (process engineering, planning, scheduling, time, as a process requirement, the return temperature
inspection, engineering, etc.) could be consolidated and of the naphtha stream to the crude column also must be
remote access of plant operation for providing solutions maintained. The temperature is controlled by TIC, the
could find roots to manage and provide the “best operating output of which goes to the control valve TV-1. Depending
zones” for operation, which could be something similar to on the return temperature, the control valve TV-1 opening
the current “global positioning system” that guides travel. gets adjusted by directly passing naphtha flows through
In other words, the response time to intervene will reduce S01 and S02 to the crude column inlet stream (see Figure
to seconds/minutes. “Carbon trading” could go live, and 14.3). If the naphtha pump around the return temperature
refineries in different parts of a country could increase or has to be increased, the control valve TV-1 will be wide
decrease their throughputs on the basis of overall green- open, limiting the flow through exchangers S01 and S02
house gas “bubble” margin. With alternate power gaining and vice versa.
impetus from most governments, the carbon trading link
could also extend to all major industries. 14.8.2 Fired Heater Control
The refinery of the future will be fully automated from 14.8.2.1 Introduction
crude blending to product blending, with many intelligent Lead-lag control is the mechanism used in fired heaters
sensors and knowledge databases to steer various real- for adjusting firing rates while ensuring safety of the
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Chapter 14 n Process Control and Instrumentation 369

Figure 14.3—Crude preheat train control.

e quipment. Complete combustion of fuel in the fired heater complete combustion is always ensured with an excess
is ensured by sending an excess amount of combustion combustion air available all of the time.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
air against the required stoichiometric quantity. A normal Heater operation is an optimal tradeoff between the
air/fuel ratio is between 1.0 and 1.6. Figure 14.4 depicts a thermal efficiency and safety of operation. This is done
typical fired heater lead-lag control configuration. by maintaining an optimum quantity of excess oxygen at
Incomplete combustion of fuel produces carbon all times in the heater box. An analyzer measuring excess
monoxide (CO), which travels along with flue gas from the oxygen is used for this purpose and acts as an input to the
radiation section to the convection section and to the heater lead-lag controller, which accordingly resets the combus-
stack via the induced draft (ID) fan. There is ample tion air flow. Suppose it is decided to maintain an optimum
probability that combustion reactions may occur in air/fuel ratio of 1.1 (10 % excess air/2 % excess oxygen),
the convection section because CO formed is reactive and and if oxygen analyzer shows a value of 1.5 %, then the
the energy required for triggering the reaction is available combustion air is adjusted accordingly so as to maintain
in the form of heat in the flue gases. The combustion design value.
reaction being exothermic in nature liberates a lot of Case 1: TIC SP is increased and as a result the con-
heat, thus increasing the chances of tube failure in the troller calls for increasing the heat input to the process
convection section. stream.
This higher signal will be ignored by the low signal
14.8.2.2 Heater Operation in a selector TY1 but will pass through the high signal selector
Hydrotreater TY2 to the flow controller (FC) for manipulating the com-
During normal operation, adjusting heater firing is a nor- bustion air control valve. The higher signal will open the
mal routine for obtaining desired specifications for the damper more and increase the combustion air flow, which
products produced. Consider fired heater operation in a is measured by flow indicator (FI) available. Now this sig-
hydrotreater. To produce different batches of diesel (differ- nal will be sent to the low signal selector TY1 via calcula-
ent sulfur specifications), the reactor inlet temperature is tion block. The low signal selector TY1 will pass the lower
varied accordingly. This is done by adjusting the firing in of TIC and comb air FI. It selects signal from comb air FI.
the heater, which is upstream of the reactor. This signal will be the new setpoint to the fuel FC and
This transition from one firing rate to the other is cause its output to increase, thereby increasing the fuel gas
done by lead-lag control with prewritten logics, which flow via the fuel gas control valve. The control system will
ensures safety and efficiency of fired heater operation. now come to equilibrium according to the new TIC setpoint.
The system ensures that when the fired duty demand Case 2: TIC setpoint is decreased and as a result
increases, the air flow increases first, followed by an this controller calls for decreasing the heat input to the
increase in fuel supply. Conversely, when demand falls, process stream.
the total fuel consumption is reduced first, followed by This lower signal will be ignored by the high signal
a reduction in combustion air supply. In this manner selector TY2 but will pass through the low signal selector
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370 Petroleum Refining and Natural Gas Processing

Figure 14.4—Fired heater lead-lag control diagram.

TY1 to the FC for manipulating the fuel gas control valve. 14.8.3 Fluidized Catalytic Reactor Control
The lower signal will close the fuel gas control valve and 14.8.3.1 Introduction
decrease the fuel gas flow, which is measured by the FI The fluidized catalytic cracking unit is a margin booster
available. Now this signal will be sent to the high signal unit in the refinery complex. This is meant for cracking
selector TY2 via calculation block. The high signal selector the long-chained molecules to comparatively smaller chain
TY2 will pass the higher of TIC and fuel gas FI. It selects the molecules having more dollar value. Figure 14.5 depicts a
signal from the fuel gas FI. typical FCC reactor-regenerator control configuration. The
This signal will decrease the setpoint to the combustion heavier feed enters the reactor and the cracking reaction
air FC, which will cause this FC to close the combustion air takes place in the riser of the reactor with the help of a cata-
control valve. The control system will now come to equilib- lyst in fluidized form. The valuable lighter products leave
rium according to the new TIC setpoint. the reactor for separation in downstream fractionators.
In both of the cases, the heater outlet temperature The coke gets deposited on the catalyst during the cracking
controller has reset the setpoint to the fuel to control heat process. Hence, the catalyst is sent to the regenerator where
input to the heater. The use of the low signal selector and the coke is burnt off using air. The hot regenerated catalyst
the high signal selector makes it possible for this output sig- is circulated back to the reactor for cracking the fresh feed.
nal to adjust the air first in the case of higher heat demand This is a continuous process and the control systems should
and then to adjust the fuel first in the case of lower heat be designed in such a way that the integrity of reactor and
demand. the regenerator are always taken care of. It is a perfectly
Safety of equipment is ensured by using lead-lag con- heat-balanced system because the heat of combustion is
trol. Transition between two firing rates is done in a smooth utilized in the reactor for providing the heat required for
manner without compromising on product specifications cracking the feed. The entire heat balance of the system
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and safety of the equipment. It reduces the excess consump- is dependent on the total catalyst circulation through the
tion of the combustion air/fuel and gas/fuel oil. system and the ratio of catalyst to oil (C/O)/feed being
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Chapter 14 n Process Control and Instrumentation 371

Figure 14.5—FCC reactor-regenerator control diagram.

maintained. (C/O) reactor-regenerator is the weight ratio of changed so that an increase in C/O occurs, an increase in
the catalyst circulated between the reactor and regenerator conversion and in coke yield will also be observed.
to the fresh feed to riser.

(C/O) reactor-regenerator =
14.8.3.2 Reactor
The heart of the fluid catalytic cracker (FCC) unit is the
Weight flow of regenerated catalyst
(14.1) riser where the reaction occurs. Hot regenerated catalyst
Weight flow of fresh feed flows to the riser bottom through the regenerated catalyst
(C/O) reactor-regenerator is not an independent variable; it standpipe where lift streams (gas/oil) preaccelerate the cat-
will increase with an increase in reactor temperature and alyst and transport it up the riser. The feed to the reactor is
decrease with higher regenerator dense bed temperature or sprayed into fine droplets using specially designed nozzles
combined feed temperatures. When process conditions are and steam for atomizing it.
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AST-MNL58-11-0801-014.indd 371 3/12/13 2:31 PM

372 Petroleum Refining and Natural Gas Processing

The hot catalyst vaporizes the feed and carries the catalyst flowing to the riser. While adjusting the opening of
catalyst upward. Cracking reactions take place within 2–3 s, the RCSV, the DP across it should always be taken care of.
which is the time required for the catalyst and hydrocarbon Hence, a low selector switch (LSS) is provided to ensure that
vapors to reach the top of the riser. Catalyst is quickly sepa- the DP across the slide valve is always positive.
rated from hydrocarbons in the reactor vessel to reduce The reactor catalyst level is controlled with a level
overcracking. recording controller (LRC) located on the reactor ves-
sel. Figure 14.7 depicts a typical FCC spent catalyst slide
14.8.3.3 Regenerator valve (SCSV) operation related control logic. The output
The regenerator is divided into two sections. The lower of the LRC resets the spent catalyst slide valve (SCSV)
section is called the combustor, where the spent catalyst opening, regulating the amount of catalyst flowing from
from the spent catalyst standpipe is distributed over the air the reactor to the regenerator. Here again, LSS is pro-

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
distributor. Also, the hot catalyst from the upper section of vided to take care of positive DP across the slide valve.
the regenerator is recirculated back to the combustor to The reactor-regenerator differential pressure is con-
provide the necessary heat to start the combustion reaction trolled by varying the regenerator pressure. This is a criti-
and for shifting the reaction toward complete combus- cal parameter to be maintained because it directly affects
tion. The upper section is called the regenerator, where the the differential pressure across the slide valves. The output
combustion reaction is completed and from where the hot from this controller resets the position of the flue gas valves
regenerated catalyst is sent back to the reactor. at the expander inlet and bypass lines of the power recovery
section to vary the regenerator pressure and maintain the
14.8.3.4 Important Process Parameters constant reactor-regenerator DP.
For economical running of an FCC unit, there are some The reactor pressure is not directly controlled because
important process parameters that need to be controlled it is governed by the speed of the wet gas compressors in
effectively all of the time. The process parameters of inter- the gas concentration section that exert a back pressure on
est are [7] the main fractionator column and thereby the reactor.
• Reactor severity (reactor temperature) The regenerator temperature is not directly controlled
• Catalyst level in the reactor and is a function of several other process variables. In
• Delta pressure (DP) across both slide valves opening simple terms, the regenerator temperature depends on the
• Reactor and regenerator DP percent delta coke on the catalyst (i.e., the coke on spent
catalyst entering the regenerator minus the coke on the
14.8.3.5 Reactor-Regenerator Process regenerated catalyst leaving the regenerator). Like many
Control other variables in the reactor-regenerator system, this too
The yield of different products from the reactor greatly depends on several factors and is a function of the total
depends on the reactor temperature, which is controlled catalyst circulation, the amount of coke deposited, and the
via a temperature recorder controller (TRC) located in the type of feed being cracked [7].
upper vapor space of the reactor vessel. Figure 14.6 depicts
a typical FCC regenerated catalyst slide valve (RCSV) opera- 14.8.4 Extractive Distillation Control Scheme
tion related control logic. The output signal from the reactor 14.8.4.1 Process Description
TRC controls the opening of the regenerated catalyst slide Extractive distillation (ED) is used for the separation of
valve (RCSV), regulating the amount of hot regenerated substances with low relative volatility that otherwise cannot

Figure 14.6—FCC RCSV operation control logic diagram.

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Chapter 14 n Process Control and Instrumentation 373

Figure 14.7—FCC SCSV operation control logic diagram.

be separated by normal distillation. A solvent that is rela- 14.8.4.3 ED Process Control

tively nonvolatile and has a high boiling point is used. The As indicated in the Figure 14.8 ED schematic diagram, the
component having a lower boiling point is separated out ED column pressure is controlled by an overhead pressure
from the top of the distillation column whereas the higher controller for which output goes to a split range controller.
boiling point component along with the solvent that it is If the pressure is lower than the setpoint (output = 0–50 %),
extracted into is removed from the bottom. This mixture is the inert gas valve opens. On the other hand, if the pres-
quite easily separable in the subsequent distillation column sure is higher (output = 50–100 %), then the vapors will be
otherwise called a recovery column. routed to the flare to maintain the system pressure.
For a typical benzene extraction system, the feed to the The temperature controller installed in the feed line
column may be a mixture of benzene and nonaromatics. The takes care of the feed inlet temperature by manipulating the
objective is to separate out benzene from the nonaromatics, bypass valve of the feed/solvent exchanger. Similarly, the
maintaining the purity of benzene (in the extract) and at the solvent temperature is controlled by adjusting the bypass
same time minimizing the losses of benzene along with non- valve of the solvent cooler.
aromatics (i.e., raffinate). The temperature at which the feed An APC scheme can be better utilized in an ED system
and the solvent enter the column is very important for the for simultaneously maintaining the benzene product purity
most effective separation. The feed has to enter at the bubble and minimizing the losses of benzene. The scheme uses the
point, whereas the solvent has to be at a temperature to just ED column reboiler duty as a main handle to control the
vaporize the lighter component (nonaromatics) while extract- following:
ing the benzene component. The column bottom temperature • Tray “p” temperature, which is a good indication of
should never exceed the solvent degradation temperature [8]. how much benzene is lost in the raffinate.
The benzene and solvent mixture from the ED column • Recovery column overhead benzene purity analyzer
enters the recovery column, where the benzene is removed (ppm of nonaromatics). For a given change in the ED
from the overhead while the lean solvent from the bottom column parameters, there is a significant dead time
is circulated back to the ED column. for the indication of nonaromatics in the recovery
column overhead. Hence, the tray “r” temperature of
14.8.4.2 Process Variables the ED column, which again is a good indication of
The important process variables that need to be controlled the amount of nonaromatics escaping along with the
are [8] solvent, can be effectively controlled.
• Column pressure for column stability Both of the temperatures mentioned above are main-
• Feed temperature and lean solvent temperature for tained within limits to ensure the optimum performance
effective separation between benzene and nonaromatics of the column. The solvent temperature, the solvent flow
• Benzene in ED raffinate and nonaromatics in extract rate, and the reflux flows are the other handles used in
• ED column bottom temperature APC.

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AST-MNL58-11-0801-014.indd 373 3/12/13 2:31 PM

374 Petroleum Refining and Natural Gas Processing

Figure 14.8—ED schematic diagram.

References [5] “Basics of Advanced Process Control, Training Module,” TES-

[1] Altmann, W., Practical Process Control for Engineers and Tech- TS-P-050, Reliance Industries, Patalganga, India, 1998.
nicians, 1st ed., Newnes, Burlington, MA, 2005. [6] Anand, K., and Manav, B., Best Practices in Building NIR
[2] Emerson Process Management, Control Valve Handbook, 4th Models for Gasoline and Diesel, Process Automation, Reliance
ed., Fisher Controls International, Marshalltown, IA, 2005. Industries, Jamnagar, India, 2008.
[3] Venkatapathy, S.R., “Increasing Importance of Smart Valve [7] “UOP Fluid Catalytic Cracking Process,” in Reliance Jamnagar
Positioners,” Machinist, April, 2009. Refinery Training Course Material, Reliance Industries, Patal-
ganga, India, 1998.
[4] “Introduction to Multivariable Predictive Control with Aspen
DMCPlus,” in AspenTech Customer Education Training Man- [8] UOP Extractive Distillation General Operating Manual, 2004.
ual, Course Number MA300.06.08, AspenTech Technology,
Burlington, MA, 2007.

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AST-MNL58-11-0801-014.indd 374 3/12/13 2:31 PM

15
Modern Computer Process Control
Refining Units
Ravi Jaisinghani1

15.1 Introduction 15.3 Control Technology—Comparison

The period from 1960 to the present may be called the Summary
period of modern automatic control. This modern period Table 15.1 and Figure 15.1 summarize the differences
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follows the periods of primitive automatic control (1868 to between regulatory (PID) control, multivariable control
early 1900s) and classical automatic control (early 1900s to (MVC), and MVPC [4]. In brief, the complexity not only
1960) [1,2]. During this modern control period, there has increases in the number of variables being simultaneously
been an ever-increasing growth of advanced process control controlled and influenced but also in past and predicted
(APC) applications such that APC has become a norm for future behavior of process variables as the technology pro-
refining and petrochemical units. APC technology has also gresses from PID to MVC to MVPC.
evolved along the well-known pyramid path [3] of regula- One of the main differences between MVC and MVPC
tory control to advanced regulatory control (ARC) to con- is that the MVC technology overlooks the transient behavior
ventional APC to multivariable predictive control (MVPC). of dependent variables. Although many refining processes
Further higher in the APC hierarchical level, real-time opti- exhibit first-order monotonous-type dynamic response, a
mization (RTO) requires a magnitude change in engineer- few reaction processes have a higher order nonmonotonous
ing work and cost because it requires first-principle models response that may be exhibited as an initial inverse response
and large-scale solution of nonlinear equations. Also, at (like in a reactor ΔT control) or as an overshoot-type
this juncture of MVPC/RTO, other related technologies— dynamic response between an input variable and an output
advisory/expert systems, neural-networks-based inferential variable. As shown in Figure 15.2, if the steady-state gain
predictions, and fuzzy logic—have been introduced to between these variables is 0.4, then to increase the output
improve the safety and reliability of the unit operation. The by 1 unit, the input will need to be changed by 2.5 units
purpose of this chapter is to identify typical APC strategies according to MVC control. However, such a large change in
for common refining processes and develop integrated con- the input will cause a transient change of 2.5 units in the
trol solutions for typical refining process units. output, which may likely cause a quality violation.
To avoid such a transitory upset, the input in this case can
15.2 Modern Process Control initially be changed by a maximum of 0.4 units only on the
With a historical base of nearly 30 years and with several basis of MVPC control. Then, after the transient response has
thousand applications implemented, MVPC technology peaked and the output is steadying out with a change of 0.16
has not only been well established and proven but has also units, the input can be changed by another increment of (1.0
become the main workhorse of refinery process control – 0.16)/2.5 = 0.336 units to avoid an overshoot in the output.
and optimization. Despite this long history and a wide base Essentially, by implementing time-deferred changes
of implementation, MVPC technology still typically takes in the input on the basis of the dynamic response curve of
between 4 and 6 months to implement and can cost several Figure 15.2 and the history of changes already made, the
hundred thousand dollars per installation. This is mainly MVC scheme is changed to an MVPC scheme as the tran-
because site- and unit-specific empirical models of the pro- sient predictive process behavior is also controlled within
cess have to be identified. the desired quality limits.
Although a powerful technology in itself, MVPC
requires a solid base of regulatory proportional integral 15.4 MVPC Technology—Brief
derivative (PID) controls to work with. And, being reliant Explanation
on accurate dynamic (empirical) models that are constantly It is important to understand the basis of MVPC control
adjusted via biasing to reconcile with actual process data, because nearly all of the major refinery process units need
the service factor of MVPC applications is improved with this technology for process control. Although details of
the availability of online analyzers or inferential predic- MVPC technology can be found elsewhere [5], in brief, an
tions (often neural-network based). To design, implement, integrated matrix approach is utilized to simultaneously
and commission a unit-wide control scheme for a refining control all targets (also termed as controlled variables
unit requires the understanding of various technologies [CVs]) in the steady and transient states by
and their integration to meet the safety, operational, and • Adjusting the manipulated variables (MVs)
economic objectives. • Monitoring and respecting process constraints

1
Intelligent Optimization Group, Inc., Houston, TX, USA
375
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376 Petroleum Refining and Natural Gas Processing

Table 15.1—Control Technology Comparison Summary

Item Regulatory (PID) Control Multivariable Control (MVC) Multivariable Predictive Control (MVPC)

Number of variables Single input, single Multiple input, multiple Multiple input, multiple output (MIMO)
output (SISO) output (MIMO)

Algorithm basis Mainly present error Present error and steady-state Previous history, present error, future
and time behavior consideration gains (when transient behavior prediction, and steady-state gains
consideration control is not important)

Integration with Required for nearly all Can be integrated with simple Can be integrated with simple constraint
optimization levels of control and constraint pushing-type pushing-type optimization
optimization as a base optimization or as an overall
control optimizer for multiple MVPCs

Implementation DCS DCS and computer based Mainly computer based

platform

Ysp
PID Control

∆X ǻ X = Kp.(ǻȯ +ȯ. ǻ t / Ti + ǻ ( ǻȈ).TD / ǻt)

ȯ= Ysp - Y
X Y
G - Single Input, Single Output (SISO)
- Works on Present Error Only

X1 Y1 MVC Control
Y2
X2 (G11 to Gmn )ss Y3
- Multi Input, Multi Output (MIMO)
- Uses Steady State Behavior
Xm Yn (Transients Ignored)

Yi, t = Gi1,ss . X1,t + Gi2,ss . X2,t + Gi3,ss . X3,t + .......... Gim,ss . Xm,t

X1 Y1 MVPC Control
Y2
X2 (G11 to Gmn)t Y3
- Multi Input, Multi Output (MIMO)
- Uses Dynamic (Transient)
Xm Yn Behavior
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Yi, t = Gi1(t) . X1,t + Gi2(t) . X2,t + Gi3(t) . X3,t + .......... Gim,(t) . Xm,t

CV TARGET MV

PID PID versus MVPC Control

CV VALUE CONTROLLER
CV = Controlled variable
DV = Disturbance Variable
CV TARGET MV
MV = Manipulated Variable
CV VALUE MVPC
MV HISTORY CONTROLLER
DV HISTORY

Figure 15.1—PID, MVC, and MVPC comparison.

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Chapter 15 n Modern Computer Process Control Refining Units 377

1 Superposition Assumption
• The effect of changes in inputs (Xs) are linearly additive
0.8
in time and magnitude on the outputs (Ys).
Response

0.6 • If DY(t) = a(t) · DX1 when X2 is constant, and DY(t) =

ǻY/ǻ;

b(t) · DX2 when X1 is constant, then by superposition, the

0.4
effects are additive in time and magnitude:
0.2
DY(t) = a(t) · DX1 + b(t) · DX2 (15.1)
0
0 5 10 15 20 25
Time 15.4.2 MVPC—Algorithm Formulation
Figure 15.2—Dynamic overshoot process response (MVC vs. • Representation of responses between dependent vari-
MVPC). ables (CVs) and independent variables (MVs and DVs)
as numeric series until the longest dynamic model
time (also known as horizon time or steady-state
• Incorporating the effect of measured process distur- time).
bances variables (DVs) [4]. • Superposition of all effects of changes in independent
MVPC relies on dynamic response models (see Fig- variables (including most recent ranges in the past
ure 15.2 for an example) to predict the response of dependent steady-state time period) on CVs.
(CVs) variables in terms of independent (MVs and measured • This calculates the predicted (dynamic) responses of
DVs) variables. The control moves in the MVs are calculated outputs (CVs) on the basis of the present and historical
to minimize the steady-state and transient response of CVs values of inputs.
from their targets while observing the high, low, and rate-of- • Supplementing the above equations with constraint
change hard limits in the MVs. The control problem formu- equations that restrict the variables between their lim-
lation is also conducive to the integration of an optimization its (for MVs) and targets (for CVs) and allowing tuning
formulation, and this often leads to a least-cost solution in based on penalty parameters:
terms of MV costs. These concepts are shown in Figure 15.3.
Abs(ΔXi(t)) <= move sizei (15.2)
15.4.1 MVPC—Linearity and Superposition
MVPC technology has two basic limitations—linearity and Low limiti <= Σ(ΔXi(t)) <= High limiti (15.3)
superposition. These limitations may require some adap-
tive techniques for dynamic models and tuning parameters Low targeti – Low slacki
to make the control implementation robust for a nonlin-
<= Yi(t) <= High targeti + High slacki (15.4)
ear process and for changing operating regions (capacity

changes, feed-type changes, ramping, etc.). • The MVs have hard limits of the type shown above.
Linearity Assumption However, the CVs, which are dependent on the inde-
• For a change in input X of ΔX, the process value Y pendent variables, can only have soft limits:
changes by ΔY irrespective of the operating region.
• For a change in input X of 2(ΔX), the process value Y High slacki ≥ 0 (15.5)
changes by 2(ΔY) irrespective of the operating region.
Low slacki ≥ 0 (15.6)
• The common transforms used are log and converting
a ratio (Y1/Y2) into a difference (Y1 – Y2) to make the
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

response appear more linear. 15.4.3 MVPC—Internal Calculation Sequence

Note: Because most processes may not strictly follow At every online iteration cycle, the MVPC algorithm goes
linearity, the MVPC formulation includes a model update step through a three-step process (there is also an initial identi-
as a part of its control execution cycle. fication step offline) as shown in Figure 15.4.

Manipulated
Variable (MV)
Controlled
Variable (CV)

T= 0 TIME

New CV Target
Controlled How to adjust the manipulated
Old CV
Target Variable (CV) variable(s) to minimize the
TIME
predicted errors from target(s).
T= 0

New CV Target
Old CV Error Controlled
Target Variable (CV)

T= 0 TIME

Figure 15.3—MVPC concepts.

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378 Petroleum Refining and Natural Gas Processing

X1 Y1
Y2
X2 (G11 to G mn) Y3
Xm Yn

Calculation Sequence Offline/Online Known Unknown

Identification Offline X, Y G
Prediction Online X, G Ypred
Model Correction Online X, Y, Ypred G
Control Online G, Y X
Figure 15.4—MVPC calculation sequence.

15.5 Refining Processes—Control i mplementation of two or more smaller applications for

Purpose and Objectives the unit. For example, in a crude unit control, the heater
The main purposes of APC in the refining processes are pass balance and heater outlet temperature controls can
• To improve the profitability and operational stability be included in the fractionator MVPC matrix. An alternate
of the unit by enforcing control objectives subject to approach would be to implement heater pass balancing
equipment and process constraints and heater outlet temperature at the distributed control
• To provide a stable and robust control platform for systems (DCS) level and then use the heater outlet temper-
(future) unit online optimization. ature as a MV and a high selection for heater tube metal
The control objectives include safety, quality, and eco- temperature (TMT) as a CV. This can result in a simpler
nomic considerations. approach without loss of APC benefits. The integration of
• Safety schemes and the platform for implementation quite often
• Maintain the process within operating and equip- becomes a personal choice.
ment constraints
• Assist operators 15.5.2 APC—Property Estimation
• Monitor performance A common point in all advanced applications is the avail-
• Quality ability of analyzers or the development of inferential
• Maintain product qualities within specifications models for quality predictions. Neural networks (see sec-
• Stabilize operations tion 15.8 also) have been used successfully in building
• Economic (subject to safety and quality priorities) these real-time inferential property estimators. In addition,
• Maximize yield of more valuable products empirical equations based on flow, temperature, and pres-
• Maximize throughput sure have also been used. Both of these calculations require
• Minimize energy consumption frequent reconciliation and model updating or model bias-
ing with laboratory updates.
15.5.1 APC Development Considerations During plant testing for dynamic model identifica-
Although there are several different refining processes and tion, laboratory samples are also frequently collected
units, some with chemical conversions and others with such that dynamic prediction models for product quali-
physical separation only, the development of integrated ties [e.g., 5 % boiling point (BP), 95 % BP, flash point,
control schemes (covering many different physical equip- pour point, and freeze point] can be identified. The
ments pieces in one unit) can be simplified by considering MVPC controller uses these models for control, and when
the control requirements of each individual process equip- online analyzer results or laboratory results become
ment. In this respect, aside from the blending unit, nearly available, the model bias correction inherent in MVPC
all refining units have a combination of some of the follow- calculations (see section 15.4.3) is performed. This pro-
ing process equipment: vides continuity of control even when laboratory analysis
• Accumulator is not immediately available or the online analyzer is not
• Heat exchanger/condenser (energy source/sink) continuous.
• Heater (energy source)
• Compressor 15.6 Refining Processes—Basic Control
• Fractionator Schemes
• Reactor Only the basic control schemes for the process equipment
The individual equipment control schemes can then be listed in section 15.5.1 are listed in Table 15.2 because the
combined by integrating them in one large matrix form control details can be found elsewhere [6,7]. Equations for
or by linking them with common variables. Following heater pass balance include the following:
the principle of lex parsimoniae (i.e., Occam’s razor)—
“All other things being equal, the simplest solution is the F = ΣFi (material balance) (15.7)
best,”—increasing the size of the control matrix does not
always result in a better solution in the long term. Ease Ti = COT (required for all i) (15.8)
of maintenance, a ripple effect of tuning changes in a
control matrix, and failure of one sensor affecting the ΣΔFi = 0 (required, for the total flow
should remain unchanged)(15.9)
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whole unit application can sometimes result in a favorable

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Chapter 15 n Modern Computer Process Control Refining Units 379

Table 15.2—Basic Control Schemes for Refining Process Equipment

Process Equipment Control Type Control Schemes
Accumulator Pressure control Vent or purge throttling
Make-up flow addition rate
Gas product draw flow rate
Level control Linear or nonlinear control
Product draw flow rate
Make-up flow addition rate
Condensers Condensate temperature, or condensing pressure Via coolant throttling. If water cooling, limit water
control velocity to achieve sensitive control and avoid fouling.
Floating pressure control via valve position control
affecting coolant throttling. For partial condensers,
floating pressure is achieved via level control (to
provide flooding) and pressure control.
Wetted surface area control. Results in differing
degrees of condensate subcooling as a function of
residence time and in nonsymmetrical dynamics.
Incondensable build-up resulting in loss of pressure
control.
Removal of incondensable:
• Fixed purge rate if economically possible
• Second pressure controller to modulate purge stream
High-speed pressure control:
• Hot gas bypass control
Vacuum column pressure control
• Variable load or surge capacity via air or gas bleed
Large ejector and small ejector combination to
reduce steam wastage if load variations can be
anticipated
Reboiler Vapor superheat temperature control or Heat media flow rate
heat duty control
Heat exchanger Parallel exchanger balancing Adjust flow rates on the basis of temperature
network difference between passes (total flow rate remains
same)—see equation 15.10 below
Adjust dead-band limits on temperature difference
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

between average outlet temperature and individual

pass temperature to avoid oscillations.
Heater Coil outlet temperature (COT) control Fuel rate feedback control based on outlet temperature
Feed rate feed-forward control
Feed temperature feed-forward control
Fuel heating value (Wobbe index, calorimeter,
specific gravity) ratio control
Excess stack oxygen control (subject to draft pressure Excess oxygen target dependent on burner
constraint) characteristics, fuel type, heater load, etc.
Excess oxygen maintained at target via stack damper
movement—damper limits based on forced/induced
draft type
Tube pass balance (coking consideration and energy Adjust flow rates on the basis of temperature difference
efficiency) between passes (total flow rate remains same)
Adjust dead-band limits to avoid oscillations
Compressor Surge control See compressor vendors information
Precise throughput control Directly manipulate the driver speed (preferable)
Suction pressure throttling
Discharge pressure throttling
Simplify start-up and shutdown Integration of speed and antisurge controllers

Copyright ASTM International

AST-MNL58-11-0801-015.indd 379 3/12/13 2:33 PM

380 Petroleum Refining and Natural Gas Processing

Then, • Maximize vacuum gas oil recovery subject to column

ΔFi = (Ti – COT) * Fi/COT (15.10) and product specification constraints
The typical product qualities of interest are 90 % BP on
where:
gasoline and 95 % BP on naphtha, kerosene diesel, and
F = total flow rate
AGO in addition to jet fuel flash point and diesel pour point.
Fi = flow rate through pass i
These product specifications and other derived properties
COT = combined outlet temperature
are inferred from calculations based on measurements of
Ti = outlet temperature of pass i
temperature, pressure, and flow. If analyzers (or neural
network models) are available, they can be used to provide
15.7 Refining Processes—Advanced feedback trim to the inferential results.
Control Schemes Conventional Control Strategies
Following the generic control objectives and the process • Parallel preheat exchanger balancing
equipment types listed in sections 15.5 and 15.5.1, and with • Crude flow ramp control
the common control strategies mentioned in section 15.6, • Atmospheric heater pass temperature balancing
specific control objectives and control schemes for some of • Atmospheric heater stack excess oxygen control
the main refining units are discussed below. Quite often, • Atmospheric heater outlet temperature control
the advanced control strategies are divided, depending on • Atmospheric tower nonlinear level control
control requirements and equipment integration, between • Vacuum heater pass temperature balancing
conventional APC and MVPC to handle system constraints • Vacuum heater stack excess oxygen control
and loop interactions. • Vacuum heater outlet temperature control
The need for MVPC technology in most refinery appli- • Vacuum tower nonlinear level control
cations is multifold: • Stripping steam/product ratio flow control (the stripping
• Processes are of multiple-input, multiple-output steam flow rates can also be MVs in the MVPC matrix)
(MIMO) type and interactive, making it difficult to tune MVPC Schemes
and control with multiple PID loops. Figures 15.5 and 15.6 summarize the MVPC control
• Dynamic response time is in hours, making it difficult schemes for the crude atmospheric and vacuum tower,
to tune conventional PID loops. respectively. Similarly, a list of potential MVPC variables is
• Nonmonotonous process response (in reactors) shown in Tables 15.3 and 15.4.
requires predictive technology. Crude Feed-Type Change
• MVPC prediction models supplemented with labora- This can be a major disturbance for the MVPC control-
tory analysis can often substitute for online analyzers. ler. To reduce the transient time in achieving a new steady
• Control can be combined with cost optimization solu- state, the MVPC models can be changed based on the crude
tion (e.g., side product yield maximization, energy sav- feed. This requires more plant testing to develop dynamic
ings, and constraints pushing) in a MVPC matrix. models for major crude types. In addition, a crude change
detector signal is required. Crude feed pump amperage or
crude feed viscosity can be used as an indication of crude
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

15.7.1 Crude Unit—Atmospheric and Vacuum feed-type change.

Simplified Description Vacuum Tower Feed Cracking
Crude feed is preheated via heat exchangers and then To ensure low-pressure vacuum, the vacuum heater
passes through a heater before the partially vaporized feed may need to be limited to avoid heater feed cracking. In
is fractionated in the atmospheric tower into wet gas, light some cases, the vacuum tower bottoms level may become
or heavy straight run, naphtha, distillates, and atmospheric erratic if feed cracking is taking place.
gas oil (AGO). The atmospheric bottoms (reduced crude)
are heated through a vacuum heater and fractionated in the 15.7.2 Fluid Catalytic Cracking Unit
vacuum tower into light vacuum gas oil (LVGO), heavy vac- Simplified Description
uum gas oil (HVGO), and vacuum residue. For lube units, In this catalytic process, heavy oils (gas oils) are con-
the vacuum tower feed is split into LVGO, lube stocks, verted into more valuable gasoline and lighter products.
and vacuum residue. Depending on market demands and Preheated fresh feed and recycle streams enter the unit at
product price structure, there is an economic incentive to the base of the feed riser where they are mixed with the
produce more of certain products. hot regenerated catalyst. The cracking reactions start when
Control Objectives—Atmospheric Tower the feed contacts the hot catalyst in the riser and continues
• Sidestream quality control (5 % BP, 95 % BP, pour until the oil vapors are separated from the catalyst in the
point, freeze point, etc.) reactor, with the control of the reaction being maintained
• Maximize feed rate against heater and column constraints by varying the catalyst circulation rate. The cracking pro-
• Maximize pumparound heat recovery subject to cess produces coke, which remains on the catalyst particle.
product quality To maintain the catalyst activity, the catalyst is regenerated
• Maximize yield, or recovery, or both for more valuable by burning off this coke with air in the regenerator, causing
products subject to column and product specification the catalyst to move continuously between the reactor and
constraints the regenerator.
Control Objectives—Vacuum Tower Control Objectives
• Sidestream quality control (5 % BP, 95 % BP) The control objectives for the reactor/regenerator sec-
• Maximize pumparound heat recovery subject to prod- tion are designed to increase performance and enhance
uct quality stability in operations:
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Chapter 15 n Modern Computer Process Control Refining Units 381

Potential Manipulated Variables Potential Controlled Variables

1. Top Reflux Flow Rate 1. Gasoline 90 % point
2. Kerosene Product Flow Rate 2. Kerosene 95 % point
3. Diesel Product Flow Rate 3. Jet Fuel Flash point
4. AGO Product Flow Rate 4. Diesel 95 % point
5. Upper Pump-Around Flow Rate 5. Diesel Pour point
6. Lower Pump-Around Flow Rate 6. AGO 95 % point Gas
7. Crude Feed Rate 7. Tower Top Temperature Condensers
8. Heater Outlet Temperature 8. Tower Mid Temperature
9. Stripping Steam Flow Rates 9. Tower Bottom
Reflux
Temperature MV 1
Potential Disturbance Variable Drum
10. Tower Flooding Limit Reflux
1. Crude Feed Type 11. Stripping Steam/ Product
Ratios CV 7
DV 1 12. Heater Maximum Tube Naphtha
MV 7 Temperature ATM CV 1
13. Heater Maximum Duty Tower MV 9
Crude 14. All relevant valve positions Upper P/A Steam
Feed MV 2
CV 8
Kero
Preheat CV 11 CV 2,3
Exchangers MV 5
Steam
MV 3
LGO
CV 10 CV 4,5
Heater MV 6 Steam
CV 9 MV 4
CV 12 Lower P/A HGO
Side
Strippers CV 6
MV 8
Desalter
Steam
Preheat CV 13
Water Brine Exchangers
Fuel Oil/Gas
Atm Residue
To Vac Tower

Figure 15.5—Crude atmospheric unit: MVPC control.

Table 15.3—Crude Atmospheric Tower: List of MVPC Variables

No. MVs CVs Disturbance Variables

1 Top reflux flow rate Gasoline 90 % BP Crude type (assay)

2 Kerosene product flow rate Kerosene 95 % BP

3 Diesel product flow rate Jet fuel flash point

4 AGO product flow rate Diesel 95 % BP

5 Upper pumparound flow rate Diesel pour point

6 Lower pumparound flow rate AGO 95 % BP

7 Crude feed rate Tower top temperature

8 Heater outlet temperature Tower mid temperature

9 Stripping steam flow rates Tower bottom temperature

10 Tower flooding limit

11 Stripping steam/product ratios

12 Heater maximum tube temperature

13 Heater maximum duty

14 All relevant valve positions

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Copyright ASTM International

AST-MNL58-11-0801-015.indd 381 3/12/13 2:33 PM

382 Petroleum Refining and Natural Gas Processing

Potential Manipulated Variables

1. Overhead Vacuum Pressure
2. Top Reflux Flow Rate
3. LVGO Product Flow Rate
4. HVGO Product Flow Rate
MV 1
5. Upper Pump-Around Flow Rate To Vacuum
6. Lower Pump-Around Flow Rate System
7. Heater Outlet Temperature
MV 5
8. Bottom Steam Flow Rate
Potential Controlled Variables
MV 3
1. LVGO/HVGO Cutpoint LVGO
2. HVGO/Resid Cutpoint CV 1
3. Tower Top Temperature CV 3
4. Tower Mid Temperature MV 2
Vacuum
5. Tower Bottom Temperature Tower
6. Heater Maximum Tube
Temperature MV 6
7. Heater Maximum Duty
Potential Disturbance Variable CV 4

1. Atm Resid Feed Rate HVGO MV 4

CV 2

Heater Wash Oil

Slop
CV 6
Vacuum CV 5
From Atm
MV 7 Feed
Residue

CV 7 Steam
Fuel Oil/ MV 8
Gas
Vacuum
Residue
Figure 15.6—Crude vacuum unit: MVPC control.

Table 15.4—Crude Vacuum Tower: List of MVPC Variables

No. MVs CVs Disturbance Variables

1 Overhead (vacuum) pressure LVGO/HVGO cutpoint Vacuum tower feed rate

2 Top reflux flow rate HVGO/residual cutpoint

3 LVGO product flow rate Tower top temperature

4 HVGO product flow rate Tower mid temperature

5 Upper pumparound flow rate Tower bottom temperature

6 Lower pumparound flow rate Heater maximum tube temperature

7 Heater outlet temperature Heater maximum duty

8 Bottom steam flow rate All relevant valve positions

9 100 N product flow rate (lubes tower) 100 N product viscosity (lubes tower)

10 300 N product flow rate (lubes tower) 300 N product viscosity (lubes tower)

11 Slop product flow rate (lubes tower) Slop/residual cutpoint (lubes tower)
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Copyright ASTM International

AST-MNL58-11-0801-015.indd 382 3/12/13 2:33 PM

Chapter 15 n Modern Computer Process Control Refining Units 383

• Maximizing conversion (severity control) consistent • Riser dispersion steam control

with high yields of the valuable products (octane bar- MVPC
rels or specific octane number) • Reactor/regenerator severity/combustion control
• Maximizing charge throughput • Reactor/regenerator pressure balancing control
• Maintaining process stability and safety through con- (between wet gas compressor and air blower)
trol of process variables such as reactor temperature, • Throughput maximization
regenerator pressure, slide valve positions, etc. • Fractionator product quality control—Typically, 95 %
• Minimizing energy consumption or endpoint on heavy naphtha, light cycle oil (LCO),
Similarly, the main objectives for the fractionator are and heavy cycle oil (HCO)
maintaining product quality within specifications and Figure 15.7 summaries the MVPC control scheme for a
maximizing energy recovery subject to product qualities. fluid catalytic cracking (FCC) unit and Table 15.5 lists the
This conversion objective is achieved in a complex envi- potential MVPC variables.
ronment of interacting combustion and severity variables FCC Online Optimization
(e.g., reactor temperature, preheat temperature, catalyst/oil In this first-principles model-based approach, the profit
ratio, and regenerator temperature) along with equipment is maximized based on gas oil feed analysis and octane
and process constraints (e.g., slide valve operating limits, requirements. The results, in terms of fresh feed rate, riser
metallurgical limits in the regenerator, combustion air temperature, etc., are sent to the MVPC controller.
blower capacity, wet gas compressor capacity, and cooling
ability in the main fractionator overhead condensers) or 15.7.3 Catalytic Reforming Unit
column limitations in the gas plant. Simplified Description
Conventional Control Strategies In a typical fixed-bed semiregenerative process,
• Parallel preheat exchanger balancing low-octane naphtha feed is converted into high-octane
• Preheater stack excess oxygen control reformate for gasoline blending by changing the molecu-
• Preheater outlet temperature control lar forms of the feedstock from long-chain naphthenes
• Stripping steam/catalyst ratio control and paraffins to aromatics, which makes the catalytic

Potential Controlled Variables Potential Manipulated Variables

1. Oxygen in Regenerator Flue Gas 1. Feed Flow
2. Regenerator Dense Bed Temperature 2. Rate Regenerator Air Flow Rate
3. Regenerator Dilute Phase Temperature 3. Riser Outlet Temperature
4. Regenerator Delta (Dilute -Dense) Temperature 4. HCGO or Slurry Recycle Flow
5. Riser Outlet Temperature 5. Regenerator Pressure
6. Regenerated Catalyst Slide Valve Differential 6. Reactor/Regenerator ∆ Pressure
Pressure 7. Preheat Outlet Temperature
7. Spent Catalyst Slide Valve Differential Pressure 8. Wet Gas Comp Suction Pressure
8. Regenerator Superficial Velocity 9. Fractionator Overhead Temperature
9. Combustion Air Blower Speed 10. LCO Product Flow Rate
10. Wet Gas Compressor Speed/Load/HP 11. HCO Product Flow Rate To
11. Catalyst Circulation Rate 12. Heavy Naphtha P/A Flow Rate MV 8 Gas Plant
12. Heater Constraints 13. HCO P/A Flow Rate
13. Heavy Naphtha 95 % Point 14. Wash Oil/Slip Stream Flow Rate to Condensers

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
14. LCO 10 % Point Bottoms
15. LCO 90 % Point 15. LCO Sidestripping Steam
Wet gas
MV 9
16. HCO 95 % Point Comp
17. Bottoms Temperature Drum
18. Heavy Naphtha P/A Duty/Feed Ratio CV 10
19. HCO P/A Duty/Feed Ratio CV 13
20. Fractionator Flooding Reactor
21. LCO Sidestripping Steam/Product Ratio
Naphtha

CV 1 MV 6 MV 3 FCC
CV 18 Frac
CV 5 Upper P/A
MV 5

CV 2
MV 15 CV 21
Steam MV 12
CV 8 Steam
CV 3,4 CV 19 MV 10
Regenerator
CV 20 LCO
CV7 CV 14,15

CV 11 MV 13 Steam
CV 17 MV 11
Lower P/A HCO
Side
CV 6 Strippers CV 16
MV 2 Air
Blower MV 14
CV 9

CV 12
Slurry

Gasoil MV 7 MV 4
MV 1
Feed
Figure 15.7—FCC unit: MVPC control.
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384 Petroleum Refining and Natural Gas Processing

Table 15.5—FCCU: List of MVPC Variables

No. MVs CVs Disturbance Variables

1 Feed flow rate Percent oxygen in regenerator flue gas Stripping steam rate

2 Regenerator air flow rate (blower vent Regenerator dense bed temperature
or stator vane)

3 Riser outlet temperature (or Regenerator dilute-phase temperature

regenerator catalyst slide valve)

4 HCO or slurry recycle flow rate Regenerator delta (dilute-dense)

temperature

5 Regenerator pressure Riser outlet temperature

6 Reactor/regenerator differential Regenerated catalyst slide valve

pressure differential pressure

7 Charge preheat outlet temperature Spent catalyst slide valve differential

pressure

8 Wet gas compressor suction pressure Regenerator superficial velocity

9 Fractionator overhead temperature Combustion air blower speed

10 LCO product flow rate Wet gas compressor speed/load/HP

11 HCO product flow rate Catalyst circulation rate

12 Heavy naphtha pumparound flow rate Heater constraints

13 HCO pumparound flow rate Heavy naphtha endpoint or ASTM

95 % BP

14 Wash oil or slip stream flow rate to LCO 10 % BP

bottoms

15 LCO sidestripping steam LCO 90 % BP

16 HCO 95 % BP

17 Bottoms temperature

18 Heavy naphtha pumparound duty/feed

ratio

19 HCO pumparound duty/feed ratio

20 Fractionator flooding

21 LCO sidestripping steam/product ratio

22 All relevant valve limits

reforming unit (CRU) a net exporter of hydrogen (H2) gas • Minimizing energy consumption
and a part of refinery H2 balance. The feed is mixed with Similar to most distillation towers, the objectives for
the recycled H2, and the combined stream is brought to the stabilizer are to
reaction temperature in a feed heater before entering into • Maintain reformate Reid vapor pressure (RVP)
the first reactor. A typical semiregenerative CRU consists • Minimize loss of benzene and pentanes in overhead
of three to four fixed-bed reactors in series and requires • Minimize butanes in the bottoms
a batch-type regeneration procedure on a periodic basis • Maintain product composition and tower stability in
to restore the catalyst to fresh catalyst conditions. In the presence of feed disturbances
meantime, the decreased catalyst activity shows up as a • Minimize reboiler energy consumption
loss of reformate yield or high inlet temperature condition. Catalytic reforming involves several interactive ele-
Because of this, the temperature profile across individual ments—achieving target octane and maximizing reformate
beds may be different. yields in an environment of changing naphtha feed types,
Control Objectives feed rate, catalyst activity, recycle H2 purity, and recycle
The control objectives for the reforming reactor section compressor capacity.
are to Aside from conventional control schemes and a MVPC
• Maintaining the product octane number target scheme, a model-based octane prediction is often included.
• Maximizing charge throughput The inferential scheme calculates research octane number
• Maximizing stabilized reformate yield (RON) from reactor temperatures, feed analysis [paraffins,
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Copyright ASTM International

AST-MNL58-11-0801-015.indd 384 3/12/13 2:33 PM

Chapter 15 n Modern Computer Process Control Refining Units 385

olefins, napthanes, and aromatics (PONA)], liquid hourly 15.7.4 Hydrocracker Unit
space velocity, estimated catalyst activity, etc. Simplified Description
Conventional Control Strategies In a single-stage unit, fresh feed and recycled hydrogen
• Heater pass temperature balancing controls are preheated in their respective heaters and combined
• Heater stack excess oxygen controls before entering the reactor. The unit may have one or more
• Heater outlet temperature controls reactors in series and/or in parallel, depending on unit capac-
MVPC ity and desired yield characteristics. To control this exother-
• Reactor weight average inlet temperature (WAIT) con- mic temperature rise, cold hydrogen quenches are injected
trol, which is based on RON octane model prediction alongside the reactors. The reactor effluent is separated in a
• Reactor temperature profile control (important for series of flash drums. Part of the vapor flash (hydrogen) is
fixed-bed CRU) purged, and high-purity makeup hydrogen is added to main-
• Maximize feed rate subject to process and equipment tain the desired hydrogen concentration. The liquid stream
constraints from the separator is fractionated and some of the liquid bot-
• Hydrogen/hydrocarbon (HC) feed ratio control tom product is often recycled back to the reactor.
• Stabilizer bottoms reformate RVP quality control Control Objectives
Figure 15.8 summarizes the MVPC control scheme The control objectives for the reactor section are
for a CRU unit and Table 15.6 lists the potential MVPC • Maintaining conversion and severity via weighted aver-
variables. age bed temperature (WABT)
Refinery Hydrogen Balance • Maximizing throughput
As refineries have both hydrogen-consuming units • Minimizing energy consumption
(hydrocracker/hydrotreater) and hydrogen-producing units The control objectives for the fractionator are
(reformer, H2 plant), the objective is to minimize net • Sidestream product purity
hydrogen production costs. The reformer excess hydrogen • Energy recovery controls
production is increased by operating at lower pressure and The hydrocracker conversion and severity control is a
higher temperature. difficult task because it involves the interaction of several

Potential Manipulated Variables Potential Controlled Variables

1. Feed Flow Rate 1. Octane Target
2. Recycle Hydrogen Flow Rate 2. Weighted Average Inlet Temperature
3. 1st Heater Outlet Temperature (WAIT)
4. 2nd Heater Outlet Temperature 3. H2/Feed Ratio
5. 3rd Heater Outlet temperature 4. Delta Temperature (1st Bed -2nd Bed)
6. Stabilizer Reflux Flow Rate 5. Delta Temperature (2nd Bed –3rd Bed)
7. Stabilizer Heater Temperature 6. Reformer Heater Constraints
7. Recycle Compressor Limits
Potential Disturbance Variable 8. Stabilizer Top Temperature
9. Stabilizer Bottom Temperature
1. Naphtha Feed Type 10. Stabilizer Top C5+ or Benzene
2. Recycle H2 Purity 11. Stabilizer Bottoms RVP
12. Stabilizer Flooding
H2 Export
Drum
Recycle
H2 Recycle
CV 3 Compressor DV 2
CV 8 CV 10
MV 2
Gas CV 7 C5+
MV 5
CV 6
CV 6
Heater Heater CV 6 Heater
DV 1
MV 2 MV 3 MV 4 CV 2,5
MV 1 CV 2 CV 2,4

Reformer
Feed Fuel Gas Fuel Gas Fuel Gas CV 12 Stabilizer

Reactor 1 Reactor 2 Reactor 3

MV 6

CV 9
Heater

Fuel
Gas
Reformate

CV 1 CV 11
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 15.8—Catalyst Reforming Unit: MVPC control.

AST-MNL58-11-0801-015.indd 385 3/12/13 2:33 PM

386 Petroleum Refining and Natural Gas Processing

Table 15.6—CRU: List of MVPC Variables

No. MVs CVs Disturbance Variables

1 Feed flow rate Octane target Naphtha feed type

2 Recycle hydrogen flow rate Weighted average inlet temperature Recycle H2 purity
(WAIT)

3 First heater outlet temperature H2/feed ratio

4 Second heater outlet temperature Delta temperature (first bed—second

bed)

5 Third heater outlet temperature Delta temperature (second bed—third

bed)

6 Stabilizer reflux flow rate Reformer heater constraints

7 Stabilizer heater temperature Recycle compressor limits

8 Stabilizer top temperature

9 Stabilizer bottom temperature

10 Stabilizer top C5+ or benzene

11 Stabilizer bottoms RVP

Stabilizer flooding

All relevant valve limits

process conditions, such as individual bed temperatures, 15.7.5 Delayed Coker Unit
recycled H2/HC feed ratio, quench rates, heat of reaction, Simplified Description
and catalyst activity. Hot vacuum residue and thermal tar feed or both are
The conversion per pass control sets the ratio of gas fed into the fractionator a few trays above the bottom. The
oil recycle to fresh feed. Because this can affect the frac- stripped feed and gasoil recycle are pumped from the bot-
tionator bottoms level, the severity (WABT) is adjusted tom of the fractionator to the coker heater. The vapor-liquid
to maintain the fractionator bottoms level. If there is no mixture then enters the coke drum where further cracking
recycle, then only the direct WABT severity setpoint control takes place as the vapor passes through the drum and the
is implemented. liquid experiences successive cracking and polymerization
Conventional Control Strategies until it is converted to vapor and coke. The severe thermal
• Heater pass temperature balance cracking produces lighter HC fractions and hydrocracker
• Heater stack oxygen control feed stocks. The unvaporized portion of the heater effluent
• Heater outlet temperature control settles out in the coke drum where the combined effect of
• Recycled H2 purity control temperature and retention time causes the formation of
• Makeup H2 flow rate control coke; hence, the term “delayed coking.” The coke produced
MVPC can be used in the steel and aluminum industries or as fuel.
• Severity control via WABT The coke drum overhead vapor enters the base of the
• Maximize feed rate subject to process and equipment fractionator and is separated into gas, naphtha, light coker
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

constraints gas oil (LCGO), and heavy coker gas oil (HCGO), which are
• Recycled surge drum/fractionator bottoms level withdrawn as products.
control Control Objectives
• Recycled H2/HC ratio control The control objectives for the delayed coker unit are to
• Fractionator product quality control—Typically, 95 % BP • Maximize unit throughput
or endpoint on heavy naphtha, 95 % BP and freeze on • Maximize liquid yield of feed
kerosene, 95 % BP and cloud point for diesel • Maintain product quality
Figure 15.9 summarizes the MVPC control scheme for • Minimize energy consumption
a hydrocracker unit and Table 15.7 lists the potential MVPC • Optimize volatile coke matter (VCM) quality
variables. • Minimize the disturbances during the coker drum switch
Refinery Hydrogen Balance • Minimize drum cycle time
As refineries have both hydrogen-consuming units Unlike other refining process units in which the pro-
(hydrocracker/hydrotreater) and hydrogen-producing units cess is continuous, the delayed coking process has some
(reformer, H2 plant), the objective is to minimize net hydro- batch characteristics when the coke drum gets full and is
gen production costs. Operating at lower temperature, replaced with a new, empty cold drum. This requires some
lower pressure, and higher space velocity decreases the adaptation in the MVPC control scheme [8]. Also, coker
hydrocracker hydrogen consumption. throughput maximization requires adjustment of feed rate

Copyright ASTM International

AST-MNL58-11-0801-015.indd 386 3/12/13 2:33 PM

Chapter 15 n Modern Computer Process Control Refining Units 387

Potential Manipulated Variables

Potential Controlled Variables
1. Feed Flow Rate 1. WABT
2. Reactor Feed Inlet Temperature 2. 1st Bed Outlet Temperature
3. 2nd Bed Hydrogen Quench Flow 3. 2nd Bed Outlet Temperature
4. 3rd Bed Hydrogen Quench Flow 4. 3rd Bed Outlet Temperature
5. Recycle Gasoil Rate 5. 1st Bed Delta Temperature
6. Recycle Hydrogen Rate 6. 2nd Bed Delta Temperature
7. Fractionator Heater Outlet 7. 3rd Bed Delta Temperature
Temperature 8. Bias 1st Bed to 2nd
9. Bias 2nd Bed to 3rd
H2 Recycle
10. Recycle Surge Drum/Fractionator Bottoms Level
MV 6 11. Recycle Gasoil/Feed (Conversion)
12. Gasoline 90 % point
13. Kerosene 95 % point
CV 17 14. Jet Fuel Flash point
CV 19
MV 2 15. Diesel 95 % point
16. Diesel Pour/Cloud point
H2 Make-up 17. Heater Constraints
18. Quench Valve Limits
CV 1 19. Compressor Limits
Purge

Bed 1 Gas
Flash
CV 2,5
CV 18 Drum

MV 3
Naphtha Kero
Reactor
CV 12 CV 13,14
Bed 2
CV 18 Stripper
CV 3,6,8 Flash
Drum
MV 4 Fractionator
MV 1 Steam
Bed 3

CV 4,7,9 Diesel CV 15,16

CV 10
MV 7

MV 5 CV 11 HGO
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 15.9—Hydrocracker unit: MVPC control.

in the presence of constraints and physical limits such as most of the C3 and heavier HCs. The rich oil is returned for
drum volume and heater TMTs so that the coke drums are stripping off the absorbed light ends to the column from
full at the end of an operator-entered drum cycle time. which it was derived. Sufficient reboil heat is added to the
Conventional Control Strategies bottom of the stripping section of the absorber-deethanizer to
• Heater pass temperature balance eliminate any absorbed ethane and methane as well as hydro-
• Heater stack oxygen control gen sulfide from the bottom liquid product. The deethanized
• Heater outlet temperature control stream then flows to a debutanizer where C3 and C4 HCs are
• Coke drum cycle time minimization by adjusting steam fractionated and taken off as overhead product. The bottom
and cooling water closely for the warming and cooling product from the debutanizer contains C5 and heavier HCs.
of the drums The overhead C3 and C4 product from the debutanizer is fed
• Nonlinear level control to a depropanizer for separation into propane and butane.
MVPC Control Objectives
• Coker charge maximization The control objectives for the gas plant unit are to
• Coke quality control • Maximize recovery of valuable C3, C4, and C5+ products
• Recycle minimization from the feed gas stream.
• Pressure minimization • Produce gas consisting mostly of methane and eth-
• Product quality control ane for use as a fuel gas or as feedstock for hydrogen
• Reduction of energy consumption production.
• Drum switch disturbance minimization • Minimize loss of propylene in the deethanizer overhead.
Figure 15.10 summarizes the MVPC control scheme • Maintain the C2 specifications of the deethanizer bot-
for a delayed coker unit and Table 15.8 lists the potential toms product as limited by the propylene product
MVPC variables. purity specifications.
• Maintain the debutanizer overhead C5+ specification as
15.7.6 Gas Plant limited by the C4 product quality specification.
Simplified Description • Maintain the debutanizer bottom C4 specification as
Compressed gas feed is fed to an absorber-deethanizer. limited by the C5+ (gasoline) product purity (RVP)
Lean oil is added in the top section of the absorber to absorb requirements.
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388 Petroleum Refining and Natural Gas Processing

Table 15.7—Hydrocracker: List of MVPC Variables

No. MVs CVs Disturbance Variables

1 Feed flow rate WABT Naphtha feed type

2 Reactor feed inlet temperature First bed outlet temperature Recycle H2 purity

3 Second bed hydrogen quench flow Second bed outlet temperature

4 Third bed hydrogen quench flow Third bed outlet temperature

5 Recycle gas oil rate First bed delta temperature

6 Recycle hydrogen rate Second bed delta temperature

7 Fractionator heater outlet temperatures Third bed delta temperature

8 Bias first bed to second

9 Bias second bed to third

10 Recycle surge drum/fractionator

bottoms level

11 Recycle gas oil/feed (conversion)

12 Gasoline 90 % BP

13 Kerosene 95 % BP

14 Jet fuel flash point

15 Diesel 95 % BP

16 Diesel pour/cloud point

17 Heater constraints

18 Quench valve limits

19 Compressor limits

• Maintain the depropanizer overhead C3 specification A neural network topology is the shape of the layered
with a minimum degree of overpurification. computation structure. It is a combination of neurons, con-
• Minimize propylene losses in the depropanizer C4 nections, and nodes. For a typical feed-forward (back propa-
product. gation) neural network, the structure is (see Figure 15.12) [9]:
Conventional Control Strategies • An input layer for receiving data.
• Deethanizer bottoms nonlinear level control • One or more hidden layers for computation. The
• Debutanizer reflux drum nonlinear level control activity of a hidden neuron depends on the activity of
• Debutanizer bottoms nonlinear level control the input neurons and the weight of the connection
• Depropanizer reflux drum nonlinear level control between the input and the hidden neurons.
• Depropanizer bottoms nonlinear level control • An output layer for results (prediction). The behavior of
• Feed drum to gas processing nonlinear level control the output neuron depends on the activity of the hidden
MVPC neurons and the weight of the connection between the
• Lean oil circulation control hidden and the output neurons.
• Tower composition controls The advantage of using neural networks for inferen-
• Energy minimization controls tial predictions of product qualities is that detailed first-
Figure 15.11 summarizes the MVPC control scheme for principles-based knowledge of the process is not required
a gas plant and Table 15.9 lists the potential MVPC variables. and the neural networks can be trained by making them
learn from historical sets of data. Training usually requires
15.8 Neural Networks—Inferential a large amount of data. Depending on the number of input,
Predictions hidden, and output units, 30–100 historical points for each
Artificial neural nets (ANN), also called neural networks, output unit would not be uncommon to train the network.
are models based on the parallel architecture of brains So, if flash point is being estimated, and the laboratory
for computing. A neural network is essentially a form of analysis is done once daily, then approximately 3 months of
nonlinear regression, Y = f(x), which maps an “n dimen- historical data would be required. However, once trained,
sion” input space into an “m dimension” output space with- neural networks are very fast in calculating the output from
out the form of f(x) being known in advance. In practice, the inputs. As an example, to develop a neural net for pre-
neural nets are especially useful for classification and func- dicting the 95 % BP of heavy naphtha,
tion approximation/mapping problems that are tolerant of
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- • The input layer would have approximately nine input
some imprecision and have lots of training data available. units for crude feed rate, crude properties (API and
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Chapter 15 n Modern Computer Process Control Refining Units 389

Potential Controlled Variables Potential Manipulated Variables

1. Naphtha 95 % BP 1. Fresh Feed to Fractionator
2. LCGO 95 % BP 2. Heater Outlet Temperature
3. HCGO 95 % BP 3. Quench Flow Rate Potential Disturbance Variable
4. LCGO Flash Point or 10 % BP 4. Fractionator Overhead Temp
5. HCGO Initial BP 5. Fractionator Overhead Pressure 1. Coker Drum Effluent Temperature
6. LCGO Pumparound Duty/Feed Ratio 6. LCGO Product Flow Rates 2. Feed Properties (API, Viscosity)
7. HCGO Pumparound Duty/Feed Ratio 7. HCGO Product Flow Rates 3. Condensate Drum Temperature
8. Bottoms API Gravity 8. LCGO Pumparound Flow Rate
9. Recycle Ratio (constraint) 9. HCGO Pumparound Flow Rate
10. Fractionator Flooding 10. LCGO Stripping Steam Flow Rate
11. Heater Constraints (TMT, Duty, Firebox 11. HCGO Stripping Steam Flow Rate
pressure) 12. HCGO Wash Oil Flow Rate MV 5

MV 4 Gas

DV 1 Quench Accumulator
Naphtha
MV 3
P/A MV 8 CV 1
DV 3
DV 3
Coke Drums
Fractionator CV 6

Steam
Stripper
CV 10 MV 10
Steam MV 6
LCGO
CV 2,4
Heater MV 12
CV 11
MV 11 Steam MV 7
HCGO
CV 3,5
MV 9
MV 2 Steam Gen
CV 7
CV 9

CV 8 Feed
Condensate MV 1
DV 2
Drum

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Coke
Figure 15.10—Delayed coker unit: MVPC control.

Table 15.8—Delayed Coker: List of MVPC Variables

No. MVs CVs Disturbance Variables

1 Fresh feed to fractionator Naphtha 95 % BP Coker drum effluent temperature

2 Heater outlet temperature LCGO 95 % BP Feed properties (API, viscosity)

3 Quench flow rate HCGO 95 % BP Condensate drum temperature

4 Fractionator top temperature LCGO flash point or 10 % BP

5 Fractionator overhead pressure HCGO initial BP

6 LCGO product flow rates LCGO pumparound duty/feed ratio

7 HCGO product flow rates HCGO pumparound duty/feed ratio

8 LCGO pumparound flow rate Bottoms API gravity

9 HCGO pumparound flow rate Recycle ratio (constraint)

10 LCGO stripping steam flow rate Fractionator flooding

11 HCGO stripping steam flow rate Heater constraints (TMT, duty, firebox
pressure)

12 HCGO wash oil flow rate

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390 Petroleum Refining and Natural Gas Processing

Table 15.9—Gas Plant: List of MVPC Variables

No. MVs CVs Disturbance Variables

1 Feed rate to the gas processing unit Deethanizer top temperature Lean oil temperature

2 Lean oil flow rate Deethanizer overhead C3 composition Feed rate to the gas processing unit (if
not a MV)

3 Deethanizer bottom temperature Deethanizer bottom C2 composition Feed rate to the debutanizer

4 Deethanizer overhead pressure Deethanizer top delta pressure Feed rate to the depropanizer
(flooding)

5 Debutanizer top temperature Deethanizer bottom delta pressure Feed composition to the gas unit
(flooding)

6 Debutanizer overhead pressure Debutanizer overhead C5 composition

7 Debutanizer bottom temperature Debutanizer bottom C4 composition

(RVP)

8 Depropanizer top temperature Debutanizer delta pressure (flooding)

9 Depropanizer overhead pressure Depropanizer overhead C5 composition

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

10 Depropanizer bottom temperature Depropanizer bottom C4 composition

11 Depropanizer top delta pressure

(flooding)

12 All relevant valve positions

Potential Manipulated Variables Potential Controlled Variables

1. Feed Rate to the Gas Processing Unit 1. Deethanizer Top Temperature

2. Lean Oil Flow Rate 2. Deethanizer Overhead C3 Composition
3. Deethanizer Bottom Temperature 3. Deethanizer Bottom C2 Composition
4. Deethanizer Overhead Pressure 4. Deethanizer Top Delta Pressure (Flooding) Potential Disturbance Variable
5. Debutanizer Top Temperature 5. Deethanizer Bottom Delta Pressure (Flooding)
1. Lean Oil Temperature
6. Debutanizer Overhead Pressure 6. Debutanizer Overhead C5 Composition
2. Feed Rate to the Gas Processing
7. Debutanizer Bottom Temperature 7. Debutanizer Bottom C4 Composition (RVP)
Unit (if not a MV)
8. Depropanizer Top Temperature 8. Debutanizer Delta Pressure (Flooding)
3. Feed Rate to the Debutanizer
9. Depropanizer Overhead Pressure 9. Depropanizer Overhead C5 Composition
4. Feed Rate to the Depropanizer
10. Depropanizer Bottom Temperature 10. Depropanizer Bottom C4 Composition
5. Feed Composition to the Gas Unit
11. Depropanizer Delta Pressure (Flooding)
12. All Relevant Valve Positions

C2 and Lighter
MV 4 CV 2
MV 5 MV 6 MV 8 MV 9
CV 1

CV 9

CV 6 C3 Product
MV 2
Lean Oil
CV 8 CV 11
CV 4 DV 1
DV 2,5 DV 3 Depropanizer
Debutanizer DV 4
Feed
Deethanizer
MV 1
MV 7 MV 10
CV 5
MV 3

CV 7
C4 Product

CV 10
CV 3

C5+ Product
Figure 15.11—Gas plant: MVPC control.
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Chapter 15 n Modern Computer Process Control Refining Units 391

Output systems offer a supporting way to improve the profitability

Layer of process unit by [13]
• Assisting operators and engineers in normal, start-up,
shutdown, and emergency situations
• Smart alarm management
Hidden • Enhancing APC/MVPC
Layer Advisory systems are a repository of knowledge and expe-
rience in many areas (operations, engineering, maintenance,
laboratory analysis, planning, and management) collected via
interviews, historical logs, incident reports, process manuals,
Input seasonal events/sales, etc., and stored in knowledge base(s) as
Layer heuristics (rules of thumb) and event-based procedures.
Figure 15.12—Neural network architecture. Because of the uniqueness of the operation of each pro-
cess unit in terms of operating variables (flow, pressure, tem-
perature, etc.), the advisory systems superimpose unit-specific
viscosity), crude feed temperature (heater outlet tem- knowledge on generic knowledge as shown in Figure 15.13.
perature), column overhead temperature, column draw
tray temperature, overhead reflux, top pumparound 15.10 Fuzzy Logic
flow rate (or duty), and heavy naphtha draw rate. Fuzzy logic is widely used in machine control, but its
Literature [9–12] mentions attempts at using neural application to chemical process control has been quite
networks for estimating the following properties: limited. However, there are processes and conditions (e.g.,
• Preflash tower binary distillation columns, batch reactors, etc.) that can
• Heavy naphtha end BP be conducive to the success of fuzzy logic applications
• Atmospheric tower without incurring the cost of engineering-extensive MVPC
• Light naphtha end BP controllers.
• Kerosene initial BP • For processes in which mathematical models may not
• Kerosene end BP be known but in which rules that adequately describe
• Kerosene crystallization point control actions under various operating conditions are
• Atmospheric diesel 50 % BP readily available via experience.
• Atmospheric diesel 95 % BP • Mathematical conventional control often assumes
• Vacuum tower linear process, time-invariant behavior, and measure-
• Low-viscosity vacuum gas oil (VGO) 95 % BP ment frequency being faster than control frequency.
• Medium-viscosity VGO flash point Fuzzy logic control is not limited by these constraints.
• Medium-viscosity VGO viscosity A fuzzy logic controller typically consists of four com-
• High-viscosity VGO viscosity ponents:
• High-viscosity VGO color 1. Fuzzifier: The process behavior is modeled as a matter
• Vacuum diesel 95 % BP of degree (in membership functions—see Figure 15.14)
• Residue viscosity rather than in precise discrete measurement. For example,
99°C = 0.3 (cold), 0.8 (normal), 0.0 (hot)
15.9 Advisory Systems 100°C = 0.0 (cold), 1.0 (normal), 0.0 (hot)
In addition to a strict mathematical approach for the con- 2. Rules: These are based on simple operating heuristics
trol of refining and petrochemical units, advisory/expert and engineering principles. For example:

If the Reactor Bed Delta Temp. rises then

Runaway suspected:
- Cut feed rate Operator
- Depressurize the unit Advisory

If the Reactor Bed Delta Temp is xx°C

above its normal, then:
- Cut feed rate by xxx BPH using Generic Process
FIC005 Knowledge
- Present Quench Valve position is
nn % open and the trend is +y % /min

If the Reactor Bed Delta Temp is zz°C

above its normal, then:
-Depressurize the Unit at mmm Unit Specific
Process Knowledge
psig/min using the depressurizing
system. DCS
Figure 15.13—Advisory system sample configuration.
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AST-MNL58-11-0801-015.indd 391 3/12/13 2:33 PM

392 Petroleum Refining and Natural Gas Processing

Discrete World Fuzzy Logic System

1.0 1.0
Definitely
Big
Degree
Big (0.9)
Degree
of belief of belief
Not Very
Small Big (0.3)
0 0
8 ft 8 ft
Height Height
Figure 15.14—Fuzzy logic: Classification.

• If tray is cold, then decrease reflux by a small [2] Lewis, F.L., Applied Optimal Control and Estimation, Prentice-
amount. Hall, Upper Saddle River, NJ, 1992.
• If tray is very cold, then decrease reflux by a medium [3] Yucai, Z., Multivariable System Identification for Process Con-
trol, Elsevier, Cambridge, MA, 2001.
amount. [4] Jaisinghani, R., GMAXC, “Multivariable Predictive Control
Here the small amount and large amount are quanti- Training Course,” Intelligent Optimization Group, 2008.
fied separately via membership functions. [5] Deshpande, P.B., Multivariable Process Control, Instrument
3. Inference engine: Society of America, Research Triangle Park, NC, 1989.
• On the basis of the values of the inputs (e.g. multiple [6] Lipták, B.G., Process Control—Instrument Engineers’ Hand-
tray temperatures), the fuzzy logic controller checks book, 3rd ed., CRC Press, Boca Raton, FL, 1995.
[7] Lipták, B.G., Optimization of Unit Operations, Bela G. Lipták,
all of the rules and activates the subconditions to be Radnor, PA, 1987.
made in the outputs (e.g. reflux flow, reboiler steam [8] Jaisinghani, R., Minter, B., Tica, A., Puglesi, A., and Ojeda, R.,
flow). “Delayed Coker Fractionator Advanced Control,” Hydrocarbon
• The output aggregation allows for a combination of Process., Vol. 72, 1993, pp. 173–178.
multiple inferences (of a single rule) via aggregation [9] Ramakumar, K.R., “Predicting Important Parameters Using
operators (e.g., MIN, MAX, and PRODUCT) of active Artificial Neural Networks,” Hydrocarbon Process., Vol. 87,
2008, pp. 81–83.
subconditions. [10] Yang H., Briker, Y., Szynkarczuk, R., and Ring, Z., “Prediction
4. Defuzzifier: Similar, but opposite of fuzzification, the of Density and Cetane Number of Diesel Fuel from GC-FIMS
output membership function is converted into a practi- and PIONA Hydrocarbon Composition by Neural Networks,”
cal number that can be implemented by a PID controller. Prepr. Pap.-Am. Chem. Soc., Div. Fuel Chem., Vol. 49, 2004,
Fuzzy logic can also be used to imitate the behavior pp. 81–84.
[11] Kataev, P., Slobodkin, W., Slavnov, A., and Heavner, L., “Crude
of a PID controller (In fact, it has been shown that a clas- Gets Smart,” ISA InTech, March 1, 2007.
sic PID controller can be matched exactly using specially [12] Bonavita,, N., and Ruggeri, G., “Neural Net-Based Inferential
selected fuzzy representations and methods [14]) in its Quality Control on a Crude Unit,” http://www05.abb.com/
simple implementation form. Then, by adding more rules global/scot/scot267.nsf/veritydisplay/2fcb0cf334d97bea8
and fuzzification, the desired nonlinear control action can 5256f9b005c407d/$file/nnoncruidunit_glasgow_final.pdf
(accessed 2011).
be enforced in routine and ad hoc conditions.
[13] Anderson, R.E., Barnett, M., and Jaisinghani, R., “Rule Driven
Optimization Boosts Plant Performance,” Hydrocarbon Pro-
References cess, Vol. 84, 2005, 59–62.
[1] Friedland, B., Control System Design: An Introduction to State- [14] “Tuning of Fuzzy PID Controllers,” Technical University of
Space Methods, McGraw-Hill, New York, 1986. Denmark, Report 98-H 871, September 30, 1998.

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AST-MNL58-11-0801-015.indd 392 3/12/13 2:33 PM

16
Refinery Inspection and Maintenance
A.L. Kosta1 and Keshav Kishore2

16.1 Introduction because of corrosion and environmental factors. Also, there is

Inspection of plant and machinery along with the associated a normal process of wear and tear in the components by way
facilities plays a pivotal role in reliable and safe refinery of mechanical rubbing, heat generation, fatigue, degradation
operations. Maintenance is the backbone of refinery opera- of material quality, etc. The combined effect of all of these
tions because wear and tear in the components by way of factors is a lowering of equipment health and so equipment
mechanical rubbing, heat generation, fatigue, degradation life, which results in low reliability. In the case that care is
of material quality, etc., is inevitable during operations, not taken at a predefined schedule, the poor equipment can
and we need to maintain the equipment/system in original result in unscheduled breakdowns, which causes a loss of
health to the level of Ex-factory conditions by performing production and increased maintenance costs. Maintenance
the necessary corrective actions from time to time. Any equip- is also essential to keep the machineries and workplace clean
ment operating continuously or intermittently requires and tidy to avoid any mishaps or accidents. Untidy workplace
maintenance to achieve its design life. At the same time, or machinery conditions are often the cause of fire or other
it is essential that the equipment should not undergo over- accidents due to slippages, etc.
maintenance, which may result in increased maintenance
costs and a change in the original settings and clearances 16.2 Maintenance
(factory settings). This aspect is much more relevant in the Oil refineries generally consist of two types of mechanical
case of mechanical and electrical equipment. equipment: static and rotary. In addition, piping of various
For maintenance, the equipment needs to be opened/or metallurgies and other utility systems such as boilers are
dismantled for inspection, and repairs are performed based also maintained by mechanical maintenance.
on visual and other examinations. Wherever required, Maintenance activities are broadly classified into the
equipment or its components are made ready for inspection following categories:
by cleaning the surface by brushing, filing, grinding, etc. In • Breakdown maintenance
certain cases suitable access is also provided using ladders, • Preventive maintenance
scaffolds, or hydraulic platforms. Inspection or observations • Predictive maintenance
are made either while the equipment is in operation or, if • Shutdown maintenance.
required, it should be stopped for inspection. In certain
cases if there is a need to enter the equipment, such as with 16.2.1 Breakdown Maintenance
towers, vessels, or furnaces, the equipment needs to be Per this practice, the equipment is allowed to run until it
made free of any foreign material, gases, etc., and brought fails. This type of maintenance causes longer downtime of
to atmospheric conditions. equipment as well as higher maintenance and inventory costs.
There are four basic areas under which separate The production schedule is disturbed because of unsched-
maintenance activities are performed in the refinery: uled outage of equipment, which leads to significant loss to
mechanical, electrical, instrumentation, and civil. industry. This practice does not presently exist.

16.1.1 Maintenance Parameters 16.2.2 Preventive Maintenance

• Man: Require proper education and training to mainte- Preventive maintenance is an age-old practice to maintain
nance and inspection personnel. equipment or facilities and is much more relevant to rotary
• Machine: Establishment of strong facilities to cater to equipment. The schedule is derived from the recommenda-
the maintenance demand. tion made by the original equipment manufacturer (OEM)
• Management: Timely cooperation among concerned as well as experience gained during operation. Generally the
sections to meet the maintenance requirement. Strong preventive maintenance schedule is timed as monthly, quar-
facility management system-standards, manuals, diag- terly, half-yearly, or yearly. On the basis of the equipment
nostic survey facilities, etc. characteristics, each refinery decides their own schedule of
maintenance. Sample checklists for preventive maintenance
16.1.2 Need for Maintenance can be found in Appendixes 1 and 2 at the end of this chapter.
Refinery operations process varieties of crude oils at different Although preventive maintenance is generally one of the
total acid numbers (TANs) with several chemicals/catalysts most acceptable norms in the industry, at times it can also
as per operational and product demand. Hence, in-service lead to overmaintenance. The schedule is thereafter modi-
exposure of equipment and facilities causes deterioration fied to avoid further overmaintenance for such equipment.
1
Indian Oil Corp. Ltd., New Delhi, India
2
Indian Oil Corp. Ltd., Panipat, India
393
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394 Petroleum Refining and Natural Gas Processing

16.2.3 Predictive Maintenance vibration is induced in the equipment. Three different

Predictive maintenance was brought into practice in the parameters can be recorded for measuring vibrations: dis-
late 1970s when gadgets and vibration monitoring tools were placement, velocity, and frequency. As a rule of thumb, it is
put into use. Predictive maintenance is a scientific method said that if the machine is less than 600 r/min, displacement
of knowing the health of equipment in advance. Measuring is measured. If the machine is between 600 and 60,000 r/
vibration, noise, lubricating oil condition, etc., of the equip- min, velocity is measured, and if it is more than 60,000
ment has helped to diagnose problems well in advance, thus r/min, frequency of the equipment is measured. On any
strengthening predictive maintenance. Use of simple tools rotary equipment, vibration is measured in three different
such as screwdrivers or iron rods (noise probe) to listen to directions—horizontal, vertical, and axial—at each of the
the noise that develops within equipment can detect problems equipment support locations (i.e., at bearings). For velocity,
in bearings components early. Once damage such as this limits provided in Appendix 3 are used for their acceptance
increases in size, it can cause generation of heat, which can or rejection.
be felt during a routine check, and may also result in paint Vibrations are measured periodically at fixed intervals
peeling off of the body of the bearing housing. and plotted against location and direction, which over a
Predictive maintenance helps in assessing the health period of time indicate the trend. If the trend is found to be
of equipment without stopping or dismantling. Signals/ increasing and approaching limits beyond acceptance, the
indications received during vibration monitoring provide equipment is subjected to vibration analysis. In such cases,
indication on likely causes of abnormality and in assessment advanced vibration analyzers are used and the probable
of the remaining operational life of the equipment. Predic- cause of vibration is established. Reference charts and
tive maintenance is basically online detection of a problem tables in Appendixes 4, 5, and 6 are used to decide what
and is the most acceptable maintenance practice in any type of measurement is required and whether equipment is
industry today. operating within acceptable vibration limits.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
16.2.3.1 Benefits of Predictive Maintenance 16.2.4 Lubricating Oil Monitoring and Its Analysis
• Maintenance can be scheduled at a convenient time. The condition of lubricating oil in a bearing is yet another
• Resources such as man-material can be arranged way of health assessment. On regular monitoring, when
beforehand. traces of metal particles are noticed in the lubricating
• Extensive damage to equipment due to forced failure/ oil with or without change in the color of lubricating oil,
breakdown can be avoided. wear and tear in the bearing components are suspected.
• Production schedule can be changed as required. This indicates that the bearing needs replacement in the
• Time to repair can be optimized, because there will not near future. This gives prior notice to plan for stoppage of
be any waiting time. equipment and arrange for requisite spares in the mean-
• Because predictive maintenance analysis is able to time. Sometimes a problem related to the oil itself may
actually pinpoint the cause of problems, the trial and contribute to wear. To locate the source of wear particles in
error method is avoided the lubricating oil, see the general guidelines in Table 16.1.
• Maximal life can be achieved from the equipment
because the equipment can continue to run until there
is no sign of further deterioration. Table 16.1—Examples of Wear Metals and
Predictive maintenance comprises the following checks Their Origin
and analyses to investigate the cause of failure so that spe- Wear Metal Possible Origin
cific corrective actions can be planned and taken in time: Aluminum Bearings, blocks, blowers, bushings,
• Vibration monitoring and trending clutches, pastors, pumps, rotors, washers
• Amplitude demodulation Chromium Bearings, pumps, rings, rods
• Peak value analysis
• Real-time analysis Copper Bearings, bushings, clutches, pistons,
pumps, washers
• Phase angle analysis
• Time waveform analysis Iron Bearings, blocks, crankshafts, cylinders,
• Lubrication oil monitoring and its analysis discs, gears, pistons, pumps, shafts
• Wear particle analysis Lead Bearings (sleeve)
• Ferrography Nickel Bearings, shafts, valves
• Blot testing
Silver Bearings, bushings, solder
• Bearing spike energy monitoring and its analysis
• Infrared thermography Tin Bearings, bushings, pistons
• Ultrasonic analysis
• Online monitoring of process parameters The following are some of the laboratory tests that help
• Motor current monitoring to identify wear:
• Casing/housing cooling water outlet temperature moni- • Spectrometric analysis
toring and trending in hot pumps/compressors. • Particle counting
• Direct reading ferrography
16.2.3.2 Vibration Monitoring and Trending • Analytical ferrography.
Vibration in equipment is either caused by loosening/ The following physical and chemical tests are generally
damage of some part or the presence of an imbalance in performed to ascertain the condition of lubricating oil and
the equipment. Whenever such phenomena take place, its future usability:
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Chapter 16 n Refinery Inspection and Maintenance 395

• Viscosity—TAN results in the generation of heat due to increased electrical

• Moisture content—total bas number (TBN) resistance. Similarly, damaged refractory material on the
• Dispersion—flash point casing of a furnace will lead to an increase in temperature,
In addition, any other tests recommended by the OEM which if monitored regularly will help in the early detection
may be performed. and repair of damaged components.

16.2.5 Monitoring of Spike Energy of 16.2.7 Ultrasonic Analysis

Antifriction Bearings Ultrasounds are the sound waves that have a frequency level
Apart from various parameters that are measured/observed above 20 kHz. Sound waves in this frequency spectrum are
during a predictive maintenance program, it is also advisable higher than what can normally be heard by humans. Non-
to monitor the condition of antifriction bearings, which contact ultrasonic detectors detect airborne ultrasounds.
are prone to develop defects under adverse conditions and The frequency spectrums of these ultrasounds fall in the
deteriorate fast. range of 20–100 kHz. In contrast to IR emissions, ultrasounds
The shock pulse monitoring technique is suitable for travel in straight lines and will not penetrate solid surfaces.
analyzing various defects of antifriction bearings. This Most of the rotating equipment and many fluid system
technique provides early information about impending conditions emit sound patterns in the ultrasonic frequency
malfunctions. The shock pulse method monitors metal spectrum. Changes in these ultrasonic wave emissions are
impacts and rolling noise such as those found in rolling reflective of equipment conditions. Ultrasonic detectors help
element bearings and gears. When two pieces of metal in in identifying problems related to component wear as well
motion contact each other, two inter-related yet distinct as fluid leaks, vacuum leaks, and steam trap failures. In
processes occur. On the initial impact, a shock or pressure addition, these ultrasounds also help in detecting sounds
wave develops and quickly propagates through the metal. from abnormally working equipment.
This shock pulse is in the ultrasonic frequency band and
typically occurs around a center frequency of 36 kHz. 16.2.8 Online Monitoring of Process
As the signal travels from its point of origin, it is dissi- Parameters
pated by carbon and other impurities in the metal. This shock 16.2.8.1 Temperature
or pressure wave is measured using the shock pulse method. The temperature of equipment, especially at bearing locations,
After getting compressed, the metal regains its shape once the can also indicate the health of equipment. When the tempera-
impact load is released. This phase of collision is vibration and ture of bearing housing remains stable, it indicates that the
the frequency depends on shape, mass, stiffness, and dampen- equipment is running without any mechanical abnormality.
ing of the metal. These shock pulse waves are measured using On the other hand, a gradual increase in temperature is an
shock pulse meters. Shock pulse actually has two readings: indication of a developing problem in the equipment and is
carpet value and the maximum value. a hint to perform a detailed equipment check.
Metal impacting metal always occurs in a rolling element
bearing. When there is no damage to the bearing, the metal- 16.2.8.2 Pressure and Flow
to-metal contact creates a background noise of shock pulse, In the case of rotating equipment (e.g., centrifugal pumps,
which is referred to as the carpet value. When the lubrication compressors, etc.), the discharge pressure must be monitored
begins to break down, there is more metal-to-metal contact and regularly. A fall in the pressure indicates an abnormality in
the carpet value increases. The most likely cause of increased the equipment, such as a loose impeller, broken shaft, etc.,
carpet value is a decrease in the protective properties of bear- which can also cause a sharp reduction in amperage of a
ing lubrication, which indicates poor lubricating conditions. motor. There is also a probability of increase in internal
When there is a defect in a bearing element, it is hit by clearances leading to internal circulation of fluid. Blockage
another element in the bearing. For example, if there is a of suction strainers causes reduction in flow and discharge
defect in the outer raceway of the bearing, the rolling element pressure and results in starvation and abnormal noise.
will hit each time it passes over the defective raceway. This
impact creates a high-amplitude burst of shock pulse that 16.2.8.3 Noise
is distinct from the carpet value. Thus, the shock pulse Noise is another parameter that can indicate the health
method helps in identifying the defects developed in an of any equipment. In normal circumstances, there is an
antifriction bearing. A similar philosophy is also true in the acceptable level of noise in the equipment that is defined
case of damage in a gear train. when the equipment is purchased. When the equipment
remains in operation, generally noise remains more or less
16.2.6 Infrared Thermography at the same level, but in the case of an abnormality, the noise
Infrared (IR) thermography is the process of generating ther- gradually increases and goes to a level that is unacceptable.
mal images of the object. Objects of different materials and This is an indication that the equipment requires a thorough
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

colors absorb and reflect electromagnetic radiation in the check. Generally 80 db of noise 1 m from the center of the
visible light spectrum (0.4–0.7 mm). Any object at a tempera- equipment is acceptable unless stated otherwise.
ture greater than absolute zero emits IR energy (radiation)
proportionate to its temperature. By using an IR ther- 16.2.9 Motor Current Monitoring
mometer, a two-dimensional visual image reflective of the Regular monitoring of motor current is another tool that
IR radiance from the surface of an object can be generated. helps in detecting mechanical and electrical problems in
Like other predictive maintenance technologies, IR tries to motors or motor-driven equipment. The motor (acting as
detect abnormality in the equipment in the form of generation transducer) senses mechanical load variation and converts
of heat. For example, a loose or corroded electrical connection it into electrical current variation. The variation in current
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396 Petroleum Refining and Natural Gas Processing

is reflective of machine condition. Analysis of these variations abnormality and, if required, equipment should be stopped
can provide an early warning of machine deterioration. for checking and corrective action taken. No effort should
be made to alter the basic design features of the equipment
16.2.10 Need for Reliability without consulting the manufacturer.
Reliability in equipment is envisaged and built right from The performance of equipment greatly depends on
the time it is conceived, designed, manufactured, operated, whether the right equipment has been selected for the
and maintained. Needless to say, even the best operation and intended use and whether the conditions prevalent during
maintenance practices cannot bring in reliability if there is operation have been considered while designing the equip-
a basic flaw in the design. Therefore, it is essential that all ment. To understand the problem, let us consider a case.
efforts must be put in place at each stage so that less effort Suppose a centrifugal pump is required for the pumping
is required during day-to-day activities and attention can of sewage, which generally has a lot of foreign material.
be paid to further development and improvement in the If a conventional centrifugal pump with closed impeller is
equipment. selected for this service, it may not function as designed.
All equipment in a plant is generally divided into four Because the liquid to be handled contains foreign material,
categories: (1) supercritical, (2) critical, (3) semicritical, and which is likely to choke or clog the pump, an open or semi-
(4) noncritical. Supercritical equipment is defined as that open type of impeller should be selected that will not cause
for which an outage will lead to a stoppage of the plant, chokage of the impeller. Similarly, if a very hot or very cold
thus affecting operation of a particular plant as well as liquid needs to be handled, the metallurgy of the equipment
other plants on the upstream and downstream side. Such should be selected accordingly.
equipment is very costly and does not have standby such as There are ample reasons for nonperformance of
turbogenerator sets, centrifugal compressors, etc. equipment, which is generally caused by an incorrect selec-
Critical equipment is that for which failure affects the tion of equipment. In many cases there is change in the
production of the plant in terms of throughput and quality specification from when the equipment was purchased and
of output. This equipment is essential for plant operation actually put into service. Hence, whenever the equipment fails
and should not be allowed to go down unscheduled. Outage of to operate as desired, one must check the design parameters
critical equipment brings undue pressure on the maintenance vis-à-vis the operating parameters before initiating any
and operation teams, resulting in urgency and higher cost corrective action.
of maintenance. Hence, it is important that critical equip- It is also essential to keep the equipment as close to
ment receives special attention when planning predictive or the original condition as possible by way of regular main-
preventive maintenance as well as daily vigil regarding its tenance, including replacement of worn-out parts. The
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

health. The required spares should be neatly maintained for recommended maintenance schedule and procedure should
easy accessibility. be strictly followed to get the optimal performance and life
Semicritical equipment is that for which breakdown of the equipment. It has been found that there is gener-
does not directly affect plant operations, quality of pro- ally a tendency to postpone scheduled maintenance if the
duction, or jeopardize safety of man and machine. This equipment is functioning normally. This can lead to gradual
class of equipment just needs care, and its frequency of deterioration and breakdown of the equipment.
vibration measurement is slightly less than that of critical
equipment. 16.2.12 Failure Analysis Techniques
Noncritical equipment is equipment that does not affect To minimize failures, it is very essential to diagnose the root
plant operations, quality of product, or safety of man and cause of failure and take corrective actions to eliminate the
machine. This type of equipment requires the least attention. same. Breakdowns are generally caused by the combined
effects of several so-called minor defects. Some of the statis-
16.2.11 Factors and Methods of Improving tical tools that are used to perform detailed failure analysis
Equipment Reliability are why-why analysis, a fish-bone diagram, Pareto charts,
The basic objective of maintenance function is to improve and failure mode effects analysis (FMEA) charts. Of these
the reliability of a plant at minimal cost. Reliability can be four statistical tools, the first three are the basic methods
improved by various means, but the major contributors to to identify and eliminate the root cause of failure and do
improve reliability are not need explanation. However, FMEA is a comparatively
• The use of trained personal that have an extensive newer technique and is explained as follows.
knowledge of the equipment, FMEA and failure mode effects and critical analysis
• The proper design and selection of equipment depending (FMECA) are methodologies designed to identify potential
on its intended use, failure modes for a product or a process to assess the risks
• Operating equipment within its designed parameters, and associated with those failure modes to rank the issues in
• Regular and effective maintenance of equipment consid- terms of their importance and to identify and perform
ering all aspects as recommended by the manufacturers. corrective actions to address the most serious concerns.
It is highly desirable for the people who operate and The function of an asset or equipment is described as the
maintain the equipment to be fully educated and trained level of performance expected out of it as designed by its
for all of its features such as design details and limitation designer. In general, FMEA/FMECA requires identification
of equipment. While the equipment is in operation, regular of the following basic information:
checks must be performed and constant vigil must be • Environment integrity
maintained for any abnormality. The level and condition of • Safety/structural integrity
lubricant, sound level, operating parameters, etc., should be • Control/containment/comfort
checked and recorded. Reasons must be established for any • Appearance
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Chapter 16 n Refinery Inspection and Maintenance 397

• Protection 1. A
vailability: A measure of uptime as well as the
• Economy/efficiency duration of downtime:
• Superfluous functions.
Schedule time – all planned delays
There are different modes when a failure may occur in Availability = (16.3)
equipment or an asset. Some of the common failure modes Schedule time
in rotating equipment are 2. E
quipment performance efficiency: A measure of
• Bearing seizure equipment condition to deliver the designed output:
• Suction line chokage
• Lube oil leak Maximum available capacity
EPE = (16.4)
• Excess load Design capacity
• Low discharge flow 3. O
perational efficiency (OE): A measure of the utili-
• Low discharge pressure zation of equipment:
• Worn-out wear rings
• Broken spring Actual capacity
OE = (16.5)
• Bad insulation Maximum available capacity
• Sheared coupling Maintenance effectiveness measures are
• Impeller jam • Compliance of PM/PDM schedule
• Motor burnt • Planning efficiency (Planned jobs/Total jobs)
The failure effects describe the result of failure. The • Compliance of work orders generated (Completed
following steps may be recorded while describing the orders/Notification generated)
effect of a failure to establish a proactive maintenance • Maintenance quality performance measures [(Total
strategy: jobs – Repeat jobs)/Total jobs]
• Evidence that failure has occurred • Maintenance cost measures such as actual mainte-
• The threat it poses to safety and environment nance cost vis-à-vis benchmark cost.
• The way it affects the operation and quality of products
• Physical damage caused by failure 16.2.14 Rotating Equipment Alignment
• The impact of failure on the overall operating cost in In a hydrocarbon industry in which there is extensive deploy-
addition to direct repair cost ment of rotating equipment such as pumps, compressors,
• The secondary damage, if any, caused by the failure fans, blowers, etc., it is very important to have the best pos-
• Action plan to repair the failure. sible alignment of two rotating pieces of equipment such as
a pump and motor assembly. Shaft alignment is the position-
16.2.13 Maintenance Performance Indicators ing of rotational centers of two or more shafts such that they
Maintenance performance indicators evaluate the perfor- are in one line when the equipment is in operation. Proper
mance of a plant in managing the maintenance systems. shaft alignment is indicated by proper centers of rotation of
The following are the criteria to measure the performance the shaft-supporting members, such as bearings.
of equipment: There are generally two basic types of misalignment: off-
• Mean time between failure (MTBF)—reliability set and angular. In the case of offset misalignment, shafts of
• Mean time to repair (MTTR)—maintainability two machines are parallel to each other but their shaft center
• Overall process effectiveness (OPE)—multiplication is not in the same line. In angular misalignment, the shaft cen-
of availability, equipment performance efficiency, and ter lines of both machines are not parallel to each other but
operational efficiency. form an angle. Misalignment primarily causes vibration in the
Equipment performance measures are defined as machine, which may lead to failure of the machine, but there
• Reliability (MTBF): Reliability is the measure of the are other associated disadvantages of misalignment such as
frequency of downtime or the mean time between • Increased energy loss.
failures • Increased load on bearings, seals, and other mechani-
cal components
Total operation time • Reduced productivity
MTBF = (16.1) • Reduced product quality
Number of failures
• Undesirable noise
• Unsafe operating conditions
aintainability: Maintainability is the measure of the
M
• Reduced equipment life.
ability to make equipment available after its failure, or
Misalignment is the most common cause of rotary
the average time taken for its repair. It is determined by
equipment failure, and it may be present when the machine
dividing the total downtime by the number of failures
is installed or it may develop during operation. Vibration
of a particular equipment.
analysis of rotary equipment helps to provide an initial
indication if the misalignment has developed in the rotary
Total downtime of failure
MTBF = (16.2) equipment. To minimize such phenomena, it is essential
Number of failures to check and correct misalignment when the equipment is
planned for preventive maintenance.
• Overall process effectiveness (OPE): OPE is the multiplica-
tion of availability, equipment performance efficiency, 16.2.14.1 Alignment Procedures
and operational efficiency. The three factors mentioned There are many ways of performing alignment of equip-
herein are defined as ment, which primarily depends on the criticality of equipment
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398 Petroleum Refining and Natural Gas Processing

and the comfort level of equipment users. The following are 16.2.14.3 Rim and Face Method
the methods generally followed for aligning equipment: The rim and face method is an improvement over the straight-
• Straight-edge method edge method and is able to measure more accurately. This
• Rim and face method method has been in use for quite some time. In this method,
• Reverse dial method one reading is taken on the rim of the coupling and the other
• Laser beam method. reading is taken on the face of the coupling (Figure 16.3). Both
The plane where the prime mover meets the equipment dial gages are fixed on the shaft of the fixed machine (i.e., a
to be moved is important. This is the plane, also known as pump) and readings of dial gages are taken on the movable
the power plane, where the equipment should be checked for machine (i.e., a motor). Shafts of both machines are rotated
misalignment. Because the equipment such as pumps/com- together and readings are observed on both the dial gages
pressors are the fixed assembly, correction is generally made after rotating the shafts simultaneously by 90º, 180º, 270º and
at the feet of the motor, which do not have rigid connections. 360º. Metal shims of suitable thickness are provided to achieve
The positions at the feet must be calculated to be able to acceptable readings on dial gages in all four positions.
make correct movements. This is the most important factor, The main limitations of these methods are
as well as the skill of the person involved in performing the • The sag of the bar limit distance over which the tech-
alignment to achieve the desired result in the shortest pos- niques can be applied.
sible time. In all of the methods readings are taken at shafts • The construction of coupling sometimes prevents
or couplings and corrections are made at the machine feet. access to the face.
• Correction is a multistage process, i.e., first eliminating
16.2.14.2 Straight-Edge Method parallelism error and then rectifying concentricity.
In the straight-edge method, the offset is measured using a • Re-measuring is required at each stage to see the
straight edge and a set of feeler gages (Figure 16.1). effects of the corrections made.
First, the offset is measured as depicted in Figure 16.1. • Axial movements of the shafts directly affect the result.
Angular misalignment is measured by using a feeler gage,
taper gage, calipers, etc. The gap difference between two 16.2.14.4 Reverse Rim Method
points 180° apart (Figure 16.2) is used to determine the In this method, two measurements are taken on the rims
direction and amount of relative slope between the shafts. of the coupling to determine the shaft offset at two points
However, this method is no longer in use because of a (Figure 16.4). The two shafts are rotated simultaneously or,
lack of precision and because it is more dependent on the
skill of the person involved in alignment.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 16.1—Measure offset misalignment. Figure 16.3—Rim and face alignment method.

Figure 16.2—Measure angular misalignment. Figure 16.4—Reverse rim alignment method.

Source (Figures 16.1–16.7): Maurya, S.L., Ghosh, A., Paranjape, D.B., and Kacker R., “Indian Oil's Reliability Improvement Report (Refineries Division),” Indian
Copyright ASTMOil Corporation
International Ltd., New Delhi, India,
2005.
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Chapter 16 n Refinery Inspection and Maintenance 399

in some cases, the measurement is done in two stages with

measurement taken from one clock but switching positions.
Shaft angularity is the slope between the two offset mea-
surement points.
The main advantages are that it gives both offset and
angle at the same time and provides for easy calculation
and plotting of alignment and corrections. Increasing
the distance between measuring points can increase the
resolution of the angle. However, this may not be practi-
cal with clock gages because the sag of the bar requires
compensation. Figure 16.6—Twin laser reverse indication method.

16.2.14.5 Laser Beam Method

Instead of steel bars and dial gages, this method uses laser
beams and electronic defectors. Major advantages of this
method are that there is no loss in measurement accuracy due
to bar sag. The system includes a laser transmitter, a detector,
and a computer that performs alignment calculations.
There are two common types of laser alignment systems
available: (1) the single laser with a single target and (2) the
twin laser using the reverse indicator technique. The single
laser with a single or double target uses autocollimation to
measure offset and angle with reflective prism (Figure 16.5).
The target simultaneously measures vertical and horizontal
components together with the angle.
This method is accurate in angular measurement over a
short distance, but it is less easy to use for rough alignment. Figure 16.7—Twin laser using the reverse indictor technique.
It cannot distinguish a side-to-side movement by itself or the
independent rotation of each shaft. To overcome this limita-
tion, a way to couple the shaft to rotate in unison is required. field of maintenance. Some of the important gadgets that
The twin laser reverse indication technique has the major are essential and used in day-to-day work are as follows.
benefits of the reverse indicator method. Two measurement • Flange spreaders: This tool provides a simple solution for
systems are used with a laser and detector in each unit separating matching flanges whenever there is a need to
(Figure 16.6 and 16.7). This technique is used to display provide a spade or replacing the gaskets in a flange joint.
real-time alignment and continually updated corrections as This tool is a hydraulic device and uniformly spreads
the machine is moved. the flange without use of any impacting device, which
The flexibility of the system comes in handy especially may be a source of spark and fire. The movement of
in rough alignment when aligning over long-distance cardan the flange spreader is controlled by application of the
shafts or cooling tower fan drives. input force. The device avoids any kind of damage that
is sometimes caused to the gasket seating face.
16.2.15 Important Tools Used in Refineries • Hydraulic torque wrenches: Hydraulic torque wrenches and
With the developments in the field of mechanical engineer- console represent the most advanced technology available
ing and the continuous requirement of high-quality mainte- for bolting purposes. This technique imparts uniform and
nance work, several tools and gadgets have been brought up measured torque on each bolt. The pressure from the
by various companies that provide safety and quality in the hydraulic console powers the hydraulic torque wrench to
ratchet with a push of the power console button, thus loos-
ening or tightening the nut faster. Depending on the size
of the nut and the pressure it requires to contain pressure,
suitable torque is applied to each bolt of the joint.
• Bolt tensioners: Application of hydraulics has allowed
us to design both loading systems instead of relying on
the inherent hit or miss inclined plane and layer (elon-
gation and torque) system. Designed bolt loads can be
achieved by using these modern solutions. By applying
a predetermined hydraulic pressure to the load cell of
the bolt tensioners, the bolt will get stretched along
its axis. Bolt tensioners are generally used in a high-
pressure system in which precise torque application is
essential for making leak-proof joints.
• Hydraulic nut splitter: Sometimes old flange joints must
be opened after many years of operation, when the nut
Figure 16.5—Laser beam alignment. has seized because of application of higher torque or
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400 Petroleum Refining and Natural Gas Processing

because antiseize compounds have not been applied: • Health assessment of the equipment for remaining life
therefore the nuts become difficult to open and pose assessment, which cannot be done during operations
a hazard if forcefully opened. Hydraulic nut splitters • Plant reliability-related issues/operational modifications/
are a handy tool on such occasions. The device cuts catalyst changes, etc.
through the larger sizes of seized nuts with no risk of To minimize the duration of shutdown, several prepara-
injury or accident. The heads of the splitter along with tory actions such as procurement, fabrication, arrangement
a cutting tool is placed on the nut, and hydraulic pressure of resources, etc., are taken well in advance. All activities
is applied to drive the wedge into the flat side of the related to shutdown maintenance can be divided into pre-
nut and cut it. shutdown activities, shutdown activities, and postshutdown
activities.
16.2.16 Tools and Pullers for Mounting/
Dismounting of Bearing/Couplings 16.2.17.1.1 Preshutdown Actions
Premature bearing failures can result because of improper
Shutdowns are planned well in advance so that all prepara-
mounting. Such failure can typically result in
tory actions are initiated and resources are arranged. The
• Damage caused during the fitting procedure
shutdown calendar is prepared for all of the units on the
• Incorrect size of shafts and housing (i.e., too tight or
basis of their frequencies, and the schedule is updated on
too loose)
a yearly basis. At least 1 year in advance the shutdown job
• Retainer lock nuts loosening during operation
list is prepared by taking feedback from all departments.
• Burred and damaged shaft and housing seals
The list comprises
• Incorrectly mounted bearing.
• Inspection recommendations
Tools and pullers designed for mounting/dismounting
• Maintenance (mechanical/electrical/instrumentation/
of bearing/couplings include
civil) related activities
• Induction heaters: The force required to mount a bearing
• Operation/production requirements
increases with bearing size. Also, the fits required for
• Process modifications for improvements in operations
mounting of a bearing on a shaft or into housing prevent
and safety
easy installation. Therefore, the bearings or couplings
• Projects and modifications activities
need to be heated uniformly. Induction heater or electric
• Materials and infrastructure required for timely and
plates are used for this purpose. Sometimes using hot
safe completions of shutdown
oil baths also fulfills this objective.
• Other miscellaneous activities
• Mechanical or hydraulic pullers: A wide range of pullers
On the basis of requirements and the time required
for mechanical dismounting of bearings and couplings
for arrangement of all such materials/infrastructure/agency
are available. These pullers facilitate easy dismounting
line-up/chemicals and catalyst procurement, etc., necessary
without much effort and without any damage to main
actions are taken to facilitate all requirements at the site of
equipment.
activities of the unit. Prior to shutdown, meetings with all
• Bearing fitting tool kit: Bearing fitting tool kits are
concerned departments are also arranged from time to time
available and are designed for quick and precise
to avoid any lapses in preparatory activities.
mounting of bearings, which minimizes the risk of
Maintenance planning plays a major role for the fulfill-
bearing damage. The right combination of impact ring
ment of all shutdown requirements and timely completion
and sleeve allows for effective transmission of mount-
of the shutdown. In certain cases there is requirement of
ing force to the bearing ring without damaging the
generating “end of run” data at various places in the unit.
bearing raceways or rolling elements. The kit contains
The same data are recorded before shutdown to compare
various sizes of impact rings, impact sleeves, and a
them with postshutdown operating conditions. It is impor-
lead-blow hammer.
tant to have a shutdown organogram showing detailed
responsibilities for each person. All of the heavy and safety
16.2.17 Shutdown Maintenance equipment should be tested and tagged before use. This is
In the refinery, it is not possible to monitor the health of all
done before shutdown.
equipment while the plant is in operation. Although vari-
Maintenance planning prepares a detailed plan with
ous techniques have been developed to monitor the external
a break-up of each activity along with estimated time and
health of equipment, assessment of internal equipment
resources during the shutdown. This helps in identifying
conditions requires stoppage. Small- to medium-sized rotary
activities and resources required on a particular day and
equipment that has a standby can be inspected while the
helps in minimizing idling of resources or overlapping
plant is in operation, but major equipment such as furnaces,
of activities. Primavera or Microsoft project software are
tanks, columns, vessels, centrifugal compressors and tur-
generally used for scheduling of activities and allocation of
bines, etc., requires shutting down of the plant at a defined
resources.
schedule. The shutdown facilitates access to all such equip-
ment for inspection and repair purposes.
16.2.17.1.2 Shutdown
16.2.17.1 Shutdown Frequency Unit shutdown is taken under close coordination with
Shutdown frequencies of a plant are decided based on the the operations, maintenance (civil/mechanical/electrical/
following aspects: instrumentations), and safety and process departments. When
• Statutory requirements various activities related to shutdown are undertaken,
• Repair/replacement of the equipment/piping requiring maintenance support is kept informed to avoid any time loss.
plant shutdown --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Once the plant is safely shut down, all of the equipment and
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Chapter 16 n Refinery Inspection and Maintenance 401

piping circuits are flushed and made free of hydrocarbons. 16.2.17.1.3 Postshutdown Actions
Clearances/work permits are issued to maintenance support After the shutdown of a plant is completed and the unit
functions. Once the gas/hydrocarbon-free equipment is is commissioned satisfactorily, a review and analysis on
handed over to maintenance, the following activities are the activities performed during shutdown is made to find
performed: the scope of further improvement. The activities that were
• Isolation of the equipment by providing spades at the planned but could not be performed and the activities that
nearest flange joint. were not planned but needed to be completed are analyzed
• Opening the manhole covers to check for the presence and planned for corrective actions. The leftover jobs in the
of hydrocarbons/gas. If found so, allow it to be gas-free/ shutdown are also reviewed and planned for early compli-
cooled down. ance. This list is also known as the “zero-hour jobs list.”
• Providing safe lights for work inside of the equipment, On the basis of this job list, if any long-term actions are
along with access, if required. required, actions are initiated to ensure availability of the
• Cleaning the equipment of all foreign material and its required materials in time.
removal wherever required.
• Offering the equipment for inspection. 16.3 Electrical Systems
• Performing inspection/detailed investigation of the The electrical power system is the lifeline of any industrial
equipment. plant. Good design, proper installation, quality assurance,
• Recommendations by inspection for any repairs to be and sound operating and maintenance practices provide
undertaken. the basic foundation for reliable and safe operation of
• Performing repairs as recommended and getting certi- electrical power systems. The expected reliable and safe
fied from inspection authorities. performance of an electrical power system is dependent on
• Performing hydraulic or pneumatic test of equipment, the following fundamental elements:
if required. • Reliability and safety considerations in system design,
• Taking clearance from operating department before including maintenance, operation, and safety aspects
closing of the manhole. • Maintenance and operation strategy to ensure long-
• Removal of spades from the flange joints provided for term reliability and safety
isolation after obtaining clearance from the operating • Development of recordkeeping and documentation
department. systems
During shutdown, progress is reviewed regularly • Development and implementation of testing and
(preferably twice in a day—one with management and inspection methods
another with working supervisors in the shutdown), which • Development of procedures to ensure personnel
helps in redeploying resources, if required, as well as safety
identifying areas of concern. Safety is always assigned top • Development of procedures of auditing maintenance
priority. Independent safety officers continuously look for and operation performance
any unsafe activities and report instantly to authorities for • The recommended practices provide constructive guid-
corrective measures. A daily progress report is prepared to ance on the requirements considered essential for
keep key personnel updated. Spares and material are made assessing the integrity of an electrical system/equipment.
available on short notice on an around-the-clock basis. Efforts
are made to maintain the schedule by working around the 16.3.1 Essential Reliability Requirements in
clock for critical jobs and at least 14–16 h of work for less Electrical System for Reliability
critical activities. All personnel involved in shutdown are To establish a highly reliable electrical system, the design
briefed about safety in advance so that the lapses do not of the system should ensure that a single failure will not
occur. Use of safety appliances and gadgets should be used cause interruption. Various factors of reliability are related
by all personal entering a “hard-hat” area. to man, machine, and management as follows:
The following are some tools/gadgets used during shut- • Man: Education and training
down to reduce duration of shutdown as well as to obtain • Machine:
quality output (see Figures 16.8–16.10 in Appendix 18): • Establishment of strong facilities for zero inter-
• Bolt tensioners ruption
• Torque wrenches • Well-designed and constructed facilities to avoid
• Nut splitters failures
• Flange spreaders • Individual facility reliability
• Portable lift for high-rise towers • Management:
• Scissor lift to access overhead piping, etc. • Cooperation of sections
• Gamma ray scanners • Facility management system (i.e., standards,
• Dehumidifiers manuals, diagnosis, etc.)
• High-pressure hydro jet clearing machine
• Tube extractors 16.3.2 Inspection and Maintenance Practices
• Plasma cutting machine for Electrical Equipment System
• Diamond cutting tools In view of the large variety of electrical equipment in the
• Kit of hydrokinetic technology (for clearing of heavily refinery electrical system, the practices considered and
fouled heater, heat exchange tubes) indicated are those that are essential for assessing equipment
• Kit for DDT (decoking decaling technology) for and systems integrity from which more specific requirements
mechanical cleaning of furnace tubes. are to be developed by the site engineers.
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402 Petroleum Refining and Natural Gas Processing

16.3.2.1 General Practices/Requirements the associated auxiliary devices, and the interconnecting

• All fixed installations and temporarily fixed installations circuits.
should be clearly and permanently identified. The switchgear structure and connections should be
• A register should be compiled of all equipment requir- given the following overall maintenance. All maintenance
ing regular test and inspection. Each item should be work should be performed with the primary and control
uniquely identified (tagged). power circuits de-energized.
• A register of distribution system “fault levels,” including • Thorough cleaning of the equipment (panel, busbars,
calculations, should be maintained. and circuit breakers), preferably using a heavy-
• For each plant, a dossier containing all relevant data duty vacuum cleaner to remove all dust and other
for equipment should be compiled. accumulations.
• For each circuit and component part, test and inspection • Checking and cleaning circuit breaker-racking mecha-
programs, which include procedures, outlining the nism and lubrication of jackscrews and gears with
extent and frequency should be prepared. lubricant.
• Safety rules and “permit to work” systems should be • Checking of primary disconnecting device contacts for
applied before any work is undertaken on electrical signs of abnormal wear or overheating. Discolorations of
equipment. the silvered surfaces are not normally harmful unless
• A permanent record should be established for all items/ an atmospheric condition causes deposits such as sul-
circuits to be regularly tested/inspected. The system fides on the contacts. If necessary, deposits should be
should contain a permanent operational history includ- removed with a good grade of silver polish and a thin
ing details of faults, repairs, modifications, and the coat of contact lubricant should be applied.
results of tests and inspections performed. • Checking tightness and continuity of all control con-
nections and wirings.
16.3.2.2 Inspection Practices/Requirements • Insulation systems must be inspected closely for signs
• Scheduled thorough examinations (on a routine or of overheating, cracking, tracking, and other defects.
planned basis) to identify those problems more likely Insulation strength tests must be performed in accor-
to occur as a consequence of age, severity of duty, and dance with the IEEE guidelines.
environmental condition • Inspection of the main contactors for excessive wear and
• Intermediate inspections (i.e., intrusive visual inspection overheating must be undertaken and the mechanisms
to assess the general condition of enclosures and inter- checked for freedom of movement. It is important that
connecting systems) manufacturer manuals are referenced for equipment-
• The frequencies should be derived based on factors specific detailed instructions.
such as • All terminals should be checked for firmness and signs
• Legislative regulations, if any of overheating.
• International/national codes and standards • Power and control cables should be examined together
• Manufacturer recommendations with the connected equipment.
• Severity of duty • The accuracy of protective devices should be checked
• Deterioration rates against manufacturer’s characteristics and the recorded
• Consequences of failure set points should be verified. For this purpose, low-
• Availability of redundant feeders/systems and the voltage secondary injection will be necessary. Primary
specific requirements of the process units injection should be performed during unit turnaround,
• Environmental conditions when there has been some dismantling of the primary/
• Possibility of inadvertent damage secondary circuits on current transformers, or when
• Associated equipment’s scheduled examinations maloperation is suspected.
(e.g., pumps in the case of motors) • Fuse type and ratings should be checked against design
• Unit turnaround specification and records.
• The correct functionality of control/protection/
16.3.2.3 Condition Monitoring Practices indication/interlocks/intertripping circuits should be
Specific methods that need to be practiced and are relevant checked against the relevant schematic diagrams as
to the operation of electrical equipment include part of the inspection program. In addition to the
• Thermography, for identifying the condition of electri- examination checks, trip and closure controls should
cal connections (e.g., busbar connections/breaker jaw be operated wherever practicable at least once a year.
contacts) • Earthing conductors should be inspected and continuity
• Vibration analysis for assessing bearing condition assessed. All terminations must be checked for firmness.
• Noise analysis (partial discharge) for assessing the • Circuit breaker shutters and locking mechanisms
condition of the switchgear should be checked for freedom of movement and correct
• Oil analysis for monitoring the condition of transformer function with the inhibiting mechanical and electrical
windings and phase current analysis for examining interlocks proven.
motor stator and rotor condition • Many types of switchgears are used in widely vary-
ing conditions. The frequency for examinations can
16.3.3 Electrical Equipment/Systems be expected to vary from one site to another. A 2- to
16.3.3.1 Switchgear and Starters 3-year interval of inspection is desirable on the basis
The practices indicated below are applicable to LV/MV of the process unit run length. More frequent intervals
switchgears from simple isolators to VCBs, starters including (annually) are required for equipment having onerous
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Chapter 16 n Refinery Inspection and Maintenance 403

duties (e.g., motor starters subjected to frequent stop/ • Transformers are rated to carry their nameplate load in
starting, duplicate transformer and radial feeder having kilovolt-amperes/megavolt-amperes with a given heat
redundancy). rise when the ambient temperature is at a standard
level. Exact values are stated on the nameplate.
16.3.3.2 Busbars • Temperature gages and readings should be regularly
• A busbar system will require isolation, which can often taken and recorded. If the gage is also equipped with
affect the operating units. Therefore, their examination a maximum temperature indicator, readings from both
is normally performed during plant turnaround or after indicators should be recorded and the maximal temper-
a severe fault fed by the system. ature indicator should be reset. Excessive temperature
• Covers should be removed and the busbars and connec- indicates an overload or perhaps some interference
tions should be checked for evidence of overheating or with the normal means of cooling.
weakening of the insulation. • The liquid level should be checked regularly, especially
• All bus mounting bolts and splice connection bolts after a long period of low load at low ambient tempera-
should be checked for tightness. ture when the level should be at its lowest point. It is
• After cleaning, megger and record the resistance to important that liquid be added before the level falls
ground and between phases of the insulation of buses below the sight glass or bottom reading of the indicator.
and connections. Because definite limits cannot be given • Pressure/vacuum gages are commonly found on sealed-
for satisfactory insulation resistance values, a record type transformers and are valuable indicators of the
should be kept of the reading. Weakening of the insula- integrity of the sealed construction. The readings
tion from one maintenance period to the next can be should be compared to the recommendations of the
recognized from the recorded readings. For MV systems manufacturer as to the normal operating ranges.
with 2.5-kV megger, the desirable value should be • All connections should be inspected for signs of over-
above 5000 Mó. heating and corrosion. Insulators and the insulating
• Bus-zone protection CTs should be examined as part of surfaces of bushings should be inspected for tracking,
the busbar examination. Relay operability should be veri- cracks, or chipped skirts, and the gasketed bases should
fied by primary injection and the trip setting proven. be inspected for leaks. The insulating surfaces should
be cleaned of any surface contamination. Damaged
16.3.3.3 Cables and Accessories insulators or bushings should be replaced. Leaks
• Insulation resistance tests between cores and from should be repaired. Pressure-relief devices should be
cores to earth should be performed on all power and inspected to ensure that there are no leaks or corrosion
control cables. and that the diaphragm or other pressure relief device
• Terminals should be examined for signs of overheating is intact and ready to function. A cracked or leaking
and confirmation of soundness. diaphragm should be replaced at once.
• Glands should be examined to confirm mechanical • The tank, cooling fins, tubes, radiators, tap changer,
condition and the electrical integrity of the earth conti- and all gasketed or other openings should be inspected
nuity where appropriate. Glands fitted to equipment in for leaks, deposits of dirt, or corrosion. Leak repair,
hazardous areas must be checked and their suitability cleaning, and painting should be done as required.
to the hazard zone confirmed Infrared inspection can be used to detect fluid levels as
• The examination of cables may be subject to scheduled well as flow restrictions in cooling tubes.
inspection on an individual basis. However, it is a more • The tank ground should be inspected for corrosion or
appropriate and acceptable practice to include cable loose connections. A grounding electrode resistance
examinations as part of the connected equipment’s test should be made.
examination schedule. • The conservator tank, inert gas atmosphere, and dehy-
drating breather equipment should be inspected and
16.3.3.4 Power/Distribution Transformers tested according to the manufacturer’s instructions.
• Inspections of transformers should be made on a regular • If liquid is to be added, it should be given a dielectric
basis. The frequency of inspection should be based on breakdown test. The liquid to be added should be at
the importance of the transformer, the operating envi- least as warm as the liquid in the transformers.
ronment, and the severity of the loading conditions. • In addition to the primary and secondary insulation
Typical regular inspection data can include load current, tests, an additional insulation test must be performed
voltage, liquid level, liquid temperature, winding hot- between the primary and secondary windings at the
spot temperature, ambient temperature, leaks, and same test voltage as the low voltage side. For safety
general conditions. reasons the winding not under test must be earthed.
• Load currents are a very important part of the recom- • For a conservator type oil insulated transformer, insu-
mended regular inspections. If the observed current lating oils should be sampled and subjected to a water
in any phase exceeds the rated full-load value, and the content and strength test. Oil levels must be checked
rated maximal temperature is exceeded, steps should and breather silica-gel changed as required.
be taken to reduce the load. • Gas analysis of large transformers is to be performed
• Overvoltages and undervoltages can be detrimental on critical duties to give an early indication of incipi-
to the transformer and the load it serves. The cause ent winding failure. The frequency can vary from 1 to
should be investigated immediately and corrective 3 years depending on the criticality, loading, etc.
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action should be taken to bring the voltage within • Tap changers should be examined for signs of overheat-
acceptable limits. ing and their operating mechanisms should be checked.
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404 Petroleum Refining and Natural Gas Processing

• Buchholz relays should be tested and the trip and • Earthing bonds must be examined to confirm mechanical
alarm functions proven. Oil and winding temperature and electrical integrity.
indicators must also be inspected and calibrated. • Where protection CTs are accessible, they must be
• Fans/pumps and their drivers must be examined as examined and the soundness of the terminations
part of the transformer program and in accordance with checked.
the motor and switchgear inspection and maintenance • All machines should be subject to nonintrusive inspec-
requirements. tion at more frequent intervals to confirm the integrity
• Transformer frame and neutral earthing must be of the machine’s external condition and compliance
closely examined with the mechanical and electrical with Ex-certification. During normal operation, visual
integrity assessed. and physical monitoring of parameters such as tem-
• Because transformers are normally very reliable, exam- perature, sound, and load current should be performed
inations need only be performed at intervals on the to enable identified potential abnormalities.
order of 3–4 years. However, nonintrusive intermediate
inspections including oil sampling tests should be per- 16.3.3.6 Fixed Lighting Installations
formed at more frequent intervals (e.g., annually). In process plants, the light fittings and circuit cables are
exposed to inadvertent damage in addition to general
16.3.3.5 Rotating Electrical Machines deterioration due to age and environmental conditions. To
The various classes of rotating equipment have many com- ensure their integrity, routine inspection is necessary with
mon features in routine maintenance (i.e., electrical and emphasis on the systems installed in hazardous areas.
mechanical). The practices indicated are of a general nature • Inspection of luminaries should be included in the
and are not intended to cover special applications. lamp-changing programs. Where block lamp-changing
• Evidence of dirt, dust, moisture, oil, and grease on programs are undertaken, sampling can be considered.
the winding should be noted, and the winding should • The lighting system cables, junction boxes, and control
be cleaned thoroughly with the solvent solution. After switchgear examinations should also be undertaken
a major cleaning, a drying process is to be done to during re-lamping.
restore the insulation to a safe level for operation. • Cables must be examined for proper glanding and
• Insulation systems must be periodically strength tested signs of damage and overheating. Circuit breakers and
in line with IEEE 43 recommendations. For machines switches must be examined in accordance with the
online of voltages greater than 440 V, where low insu- requirements.
lation values are apparent, a polarization index test • Luminaries should be examined and their electrical
should be performed and the extent of deterioration and mechanical integrity should be confirmed.
since the last test should be evaluated. • Ex-certified equipment must be inspected in accor-
• Phase current analysis is an additional technique dance with the requirements of hazardous area
that may be considered as a noninvasive alternative equipment.
to dielectric loss analysis (DLA) or partial discharge • Emergency fittings provided with integral batteries and
analysis (PDA). associated electronic controllers should be examined in
• On HV machines, during machine overhaul, the condi- accordance with the requirements of power electronic
tion of windings including wedges and overhangs must equipment.
be established. • Where emergency lighting installations are provided
• The terminals and cable/winding tails must be exam- as total systems with central batteries and separate
ined for signs of overheating and the soundness of the cabling and control equipment, the inspection and
terminals must be confirmed. The condition of termi- testing should take into consideration both the compo-
nal boxes, cables, and glands must also be examined. nents of the system individually and the total operation
• Compliance checks should be performed in accordance of the system.
with requirements for equipment in hazardous areas.
• Bearings should be subject to monitoring in accor- 16.3.3.7 Earthing and Bonding Systems
dance with the site’s condition monitoring policy. • Earthing bonds attached to all electrical equipment
External inspection at the time of greasing will deter- (e.g., switchgear and motors, etc.) must be exam-
mine whether the bearings are operating quietly and ined with the mechanical and electrical integrity
without undue heating. established.
• The bearing housings can be opened to check the con- • Earth electrodes must be closely examined. Where
dition of bearing and the grease as per the vibration practical, they should be disconnected and the
analysis results. The bearing and housing part should impedance should be measured. Note: This may only
be thoroughly cleaned and new grease should be be performed when plant operating conditions permit.
added. Standard greasing practices should be strictly • Earth nests must be closely examined and the mechani-
adhered to as per manufacturer recommendations. cal integrity assessed. Terminations should be broken
• The general condition of the frames must be inspected and inspected to ensure that electrical continuity is not
with particular attention being given to the fan and impaired.
couplings. • All connections to structures, tanks, vessels, and tow-
• Cooling systems must be examined to ensure airways ers must be closely examined with the electrical and
and filters are free from debris and obstructions. Anti- mechanical integrity assessed. Where practical, termi-
condensation heater insulation and continuity must be nations should be broken and inspected to ensure that
tested and the control function proven. continuity is not impaired.
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Chapter 16 n Refinery Inspection and Maintenance 405

• The earth bonding system to the roof on floating roof • Controls examined and functionally tested
tanks should be closely examined and the electrical and • Protection tested.
mechanical integrity assessed. Where practical, termi- • The inspection of welding equipment should ensure
nations should be broken and inspected to ensure that that separate earth-free terminals have been provided.
continuity is assessed. Scraping earths must be closely • Portable testing equipment must be regularly inspected
examined and the integrity of the bonding assessed. and calibrated against standard supplies. This is par-
• Neutral earthing resistors must be inspected and the ticularly important for equipment used to test at high
mechanical and electrical integrity confirmed. The voltage (i.e., phasing sticks). Leads used with test
resistance must be measured and the value assessed equipment must also be closely examined and their
against the design specification. electrical and mechanical integrity established.
• When the equipment or any part of the associated • As a guide, industrial equipment should be examined
circuit is in a hazardous area, care must be taken to on an annual basis.
ensure that the testing does not in itself create a hazard.
• At loading terminals, flexible-bonding systems should 16.3.3.9 Inverters and Chargers/Static
be closely examined with the mechanical and electrical Devices (Inclusive of Batteries)
integrity established. Earth monitoring systems must • Examination in accordance with manufacturer’s rec-
be closely inspected with the functionality of monitor- ommendations, including a proof test of protective
ing/interlocks and alarm functions proved. devices, electrical integrity checks, and operational
• The earthing associated with electrical equipment functionality, must be performed.
should normally be included in the equipment’s routine • Nonintrusive inspection shall include a check of any
examination schedule. air filter and ventilation fans. Capacitor banks, chokes,
• For systems installed in hazardous areas, inspections transformers, and components generally must be
should be performed at more frequent intervals on the checked for signs of overheating.
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basis of a site’s particular circumstances and environ- • Full examination may, depending on the arrangement,
ment. Typically, for loading gantries, flexible connec- require the system to be taken out of service or put on
tions may need to be checked at weekly intervals. bypass. This may inconvenience plants or jeopardize
• Tank and vessel earthing systems are to be normally reliability of critical supplies. It is therefore common
included in their respective inspection schedule. practice to include the full examinations in plant over-
haul programs.
16.3.3.8 Portable and Transportable • Nonintrusive inspections will depend to a large extent
Electrical Equipment on the local operating and environmental conditions.
• All portable equipment including extension leads must However, as a general guide, a frequency on the order
be inspected and approved as suitable for the purpose of 1 year would be appropriate.
intended. The equipment must be registered and a • Routine operating checks should be performed on a
record maintained of subsequent inspection findings. weekly/monthly basis as per the criticality and environ-
• Portable equipment for use in the field (plant) should ment conditions, with the critical parameters being
be tagged with a label that clearly shows when the • Checking of input voltage, output voltage, and out-
equipment must be re-examined. put current to be within limits
• The plug, sockets, and the operating voltage should • Checking of battery trickle charge current
be examined to ensure compatibility with the systems • Checking of diagnostic alarms and annunciation
onsite. • Checking of abnormal heat and noise
• For all equipment there must be a careful inspection • Checking status of boost charger “auto mode”
for signs of damage or deterioration, including, for • Periodic inspection of battery banks should be per-
example, the casing, weatherproof seals, the plug/sock- formed for ensuring the health of the batteries. For
ets, terminals, cables, and anchoring devices. lead acid/nickel cadmium batteries, the routine visual
• The special features of certified (Ex-equipment) should inspections should include electrolyte levels, cracks
be checked for compliance. Certification labels must be in jars, evidence of corrosion at terminals/connectors,
firmly attached. ambient temperature, ventilation, etc.
• Transforming equipment must be inspected and its • Back-up battery systems must be regularly inspected
electrical integrity checked. For isolating transformers, and maintained in accordance with the manufacturer
the insulation between primary and secondary wind- recommendations. It is important to ascertain that
ings must be verified and the output voltage checked batteries can continue to support loads for the periods
for compliance with factory standards. specified. Therefore, load tests (discharge) must be
• Protective devices where fitted should be tested and performed and the performance checked against the
their functionality should be confirmed. battery discharge characteristic.
• Equipment provided with basic insulation and hav-
ing an earthed metal frame for protection must have 16.3.3.10 Valve Actuators
the earth conductor subjected to a substantial current • Integral motor and contractor insulation should be
continuity test. The insulation must also be measured. tested and inspected for signs of overheating on insula-
Note: For this purpose, a portable appliance tester may tion, terminations, and contacts.
be useful. • Control circuits must be verified against schematics.
• Portable generators must have Integral torque and limit switches must be checked for
• Windings to frame the IR measured correct settings.
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406 Petroleum Refining and Natural Gas Processing

• The condition of the frame and cable glanding must be • Shutdown maintenance: Scheduled, fixed-interval (based
assessed and the compliance with the Ex-certification on plant shutdown schedule), preventive maintenance
must be confirmed. plan. Generally used with opportunity for reducing
• Nonintrusive inspection of actuators, including Ex- failures.
certification checks, should be performed at a frequency • Special repairs: Comprises modifications, retrofit, re-
of 2 years. Major examinations, including limit and design/corrective engineering, technology upgrades,
torque switch checks, should be performed at frequencies software/release upgrades (in conjunction with hardware
on the order of 4 years. upgrade, if necessary).
An effective maintenance management should broadly
16.3.3.11 Hazardous Area Equipment encompass the following:
• The Ex-certification of all components and the methods • Skilled personnel with commensurate technical
of installation must be examined for compliance with qualifications/training.
the classification requirements of the area. • Availability of special tools and test equipment/facilities.
• Enclosures, glasses, seals, gland rotating elements, • Established work procedure and work instructions.
special flanges, etc., should be examined closely for • Careful planning to minimize MTTR.
defects that could impair the Ex-effectiveness. • Strategies toward increasing mean time between fail-
• Weather proofing systems must be checked and effec- ures (MTBF).
tiveness established. • Effective failure analysis system/procedure, incorporat-
• Insulation of the equipment/systems must be measured. ing FMECA.
Terminations must be proven sound. • Standards for calibration equipment. Standards should
• Earth bonds should be checked for soundness and the be derived from parameters established by the National
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earth resistance and loop impedance must be measured. Bureau of Standards (NBS).
• An electrical apparatus must not be opened in a hazard- • Realistic (on the basis of experience and OEM recom-
ous area until it has been properly isolated (including mendations) calibration and test frequencies.
the neutral from its source of supply and precautions • Use of recommended practices of OEMs on specialized
taken against its reinstatement). systems/instruments/hardware.
• For pressurized Ex “P” equipment, the special require- • Coordinate spare parts management ensuring avail-
ments are as follows: ability in time.
• Protective gas must be sampled and proven to be • Perform maintenance audit once every 3 years/as per
free of contaminants. experience or circumstances.
• Pressure/flow must be checked for adequacy. • Assess system obsolescence from time to time on the
• Pressure/flow alarms, indicators, and interlocks basis of technology trends/product releases and initiate
must be tested and functionally must be checked. upgrading plan.
• Start-up purge cycle equipment must be inspected • Conduct failure analysis of all failures to determine the
and tested in accordance with specifications. root cause and ensure that the knowledge is put to use
• The condition of ducting must be assessed and to prevent similar failures.
alarms must be tested.
• The condition of pressurized enclosures must be 16.4.2 Control Measures for Improving
inspected. Maintenance Effectiveness
• For increased safety (Ex “e”) & Type N protection • Ensure a mechanism is in place for authorization of
(Ex “n”), the adequacy of motor air gaps and running programmable logic controller (PLC)/interlock logic
clearances must be checked along with the condition of bypassing and that the bypass has been removed
gasket healthiness. subsequently and the logic/protection system is fully
operational.
16.4 Instrumentation Maintenance • Maintain backup of all distributed control system
16.4.1 Objectives (DCS)/PLC software, programs, logic/interlock ladder
• Higher availability and reliability diagrams on CDs/pen-drives and create facility for
• Minimize downtime proper preservation. Put in place a suitable responsi-
• Prevent unscheduled interruption bility matrix for the same. Also, ensure that they are
• Ensure safety of equipment and people updated at quarterly intervals or per experience and
• Minimize effect on environmental pollution. circumstances. Updating should also be ensured after
Maintenance activities are classified into the following every modification/upgrade job.
categories: • Recordkeeping: Maintain history and trend of equip-
• Breakdown/corrective maintenance: Emergency/unsched- ment performance. “As found” and “as calibrated” data
uled maintenance driven by breakdown/failure. should be made available through PC-based systems.
• Preventive maintenance: Scheduled, periodic, fixed-interval Facility for “work order” information should also be
maintenance program with thresholds established to incorporated.
indicate when potential problems could happen. • Documentation control: Document updating should
• Predictive maintenance: Maintenance program that is be performed for all modifications, changes to loop
based on trend detection through data analysis that schematics/hook-up drawings, piping and instrumenta-
gives an insight into likely causes of impending failures. tion diagrams (P&IDs), interlock logic/ladder diagrams,
Advanced maintenance action is initiated accordingly, trip settings, calibration ranges, etc., immediately upon
which prevents an impending failure. completion of the job
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Chapter 16 n Refinery Inspection and Maintenance 407

• Test/calibration equipment traceability for accuracy, civil maintenance. The following areas are broadly covered
resolution, etc. under civil maintenance.
• Rodent control measure/treatment in and around
control rooms housing DCS, PLC, and other electronic 16.5.1 Buildings
hardware and communication cables that are suscep- Office buildings, control rooms, workshops, the operator’s
tible to damage. cabin, and other buildings in the refinery are repaired and
• Ensure positive pressurization of the control room to maintained regularly. Scheduled visual inspection of the
prevent ingress of airborne dust and gaseous contami- buildings is done every year. The designer’s specification
nants. Air curtains and double doors at all entrances to of the materials and application procedure for repair is
control rooms should be maintained. followed for maintenance.
• Ensure presence of air handling unit (AHU) filters/
chemical filters as necessitated by control room ambi- 16.5.2 Structures
ence category. The flare stack, chimneys, cooling tower, piping structures,
• Ensure presence of humidity control in control room equipment structures, etc., are included in this category. The
air conditioning and that it is in operation. High inspection of these is performed along with maintenance
humidity accelerates destructive corrosive effects. On and inspection shutdowns of the plant or related activities.
the other hand, low humidity may cause electrostatic The designer’s specification of the materials and application
discharge problems with the electronic equipment. procedure for repair is followed for maintenance. The
• Ensure that a periodic survey is done to maintain and remaining life assessment of concrete stacks and chimneys is
enhance the control room ambience. performed before the estimated design life or any remarkable
• Perform an audit of DCS and PLC systems through deterioration is observed during routine visual inspections.
the OEMs as necessitated after a reasonable period of The repair/rectification is only performed under consultation
operation and driven by failure trends or as per OEM of designer, if required.
recommendations vis-à-vis necessity for a stagewise
upgrade to adopt the latest technology, facilities, and 16.5.3 Roads and Culverts
features. All refinery and peripheral roads, culverts, hard surface
• Implement online continuous monitoring of control areas under piping, tank dykes, etc., are maintained as per
room ambience. requirements. Annual maintenance after monsoon season
• Ensure that coatings conforming to severity class on is performed for all of the observations.

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DCS/PLC hardware are applied on electronic modules
and printed circuit boards. 16.5.4 Environment Protection and Sanitation
A refinery primarily deals with crude oil and has various
16.4.3 Spares Philosophy unwanted gases that are not environmentally friendly.
• In general, 5 % for all field instrumentation, subject to Cooling water is used as a cooling media of the process
a minimum of one number of each size and type. and can become contaminated during refinery operations.
• DCS/PLC: Nonredundant cards/hardware should be Planting new trees and their regular maintenance and hor-
5 % in general or at least one number of each type. ticulture activities are done to preserve the environment
Redundant cards/hardware should be at least one num- and comply with legislative requirements. Water quality
ber against each type. is also monitored regularly and the necessary treatment is
• Control valves: done to meet legislative requirements.
• One number plug and seat assembly and seal
rings for each valve under cavitation/flashing/high- 16.5.5 Drainage System
pressure services. Hydrocarbon and water waste are unavoidable in refin-
• 5 % in general for ery operations. These wastes are suitably drained to
■■ Diaphragm of actuators desired locations for further treatment and disposal as
■■ Gland packings per the environmental norms. Repair and maintenance
■■ Positioner spares of all such drains are done on a regular annual basis in
■■ Bonnet gasket set dry seasons.
• Annubar/pitot tube: One set of gasket, “O” ring, packings,
and needle valve. 16.5.6 Refractory and Insulation
• Rotameter/level troll: One number float, torque-tube Refinery operations require several furnaces, reactors,
assembly, PCB for each range, and set of packing for columns, vessels, and a vast network of process piping that
each size and type. requires application of various refractory and insulation
jobs to meet the process requirements as well as to achieve
reliable operation of the equipment. A similar requirement
16.5 Civil Maintenance Practices is also applicable for steam-generation systems. Selection,
Civil maintenance is primarily associated with the main- procurement, and application of all such refractory, cast-
tenance of all buildings/structures, roads, environmental able, and insulating materials are performed. Maintenance
protection, sanitation, and drainage-system-inclusive general activities are normally done during the planned mainte-
housekeeping in the refinery. In addition, repair of furnace nance and inspection activities of the equipment or during
refractory/castables/CF blankets, all paintings (normal/ an available opportunity. The designer’s specification and
epoxy-based), specialized paintings in the tanks/vessels, manufacturer’s application procedures are applied for the
tank cleaning, fire proofing, etc., are also taken care of by maintenance activities.
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408 Petroleum Refining and Natural Gas Processing

16.5.7 Paints and Epoxy Coating condition during service is safe and reliable for plant
Atmospheric corrosion of all external surfaces of steel/ operation. The inspection frequency and type of inspection
concrete is inevitable because of climatic conditions and the depend on the nature of deterioration. Thickness loss, local-
refinery operational environment. Also, internal corrosion ized corrosion, environmental cracking, and metallurgical
and deterioration of the equipment occurs because of various degradation are the main considerations during inspection.
process conditions. Hence, suitable painting is done on To assess the health of the equipment, predict the life
such equipments/structures as per the corrosion expert’s expectancy of the equipment, and decide plant/equipment
advice. High-temperature aluminum paints are applied shutdown for repair/replacement, inspection develops a
on the external surface of metallic stacks, chimneys, and systematic method for identifying the deteriorated compo-
the equipment/piping operating at higher temperatures. nents, structures, and equipment in a cost-effective manner
Epoxy painting is done at the internal surface of tanks, without compromising safety. It provides sound technical
vessels, heat exchanger water-side components, etc., as per evaluation of equipment conditions by way of various mon-
the advice of corrosion experts. The surface preparation itoring systems and suggests technoeconomical measures.
required for normal painting, high-temperature aluminum Inspection develops and standardizes inspection frequencies,
painting, or epoxy painting is religiously maintained as per techniques, tools and instruments, documentation systems,
Swedish standards, and painting is done as per the applica- spare management systems, etc. Quality assurance of all
tion procedure provided by the manufacturer. projects and modification activities, repair and maintenance
activities, selection of materials, development of repair pro-
16.5.8 Storage Tank Cleaning cedures, etc., is done within the framework of international
Crude oil, intermediate products, and finished products codes and practices.
are stored within the refinery premises itself. The storage
is in tanks, vessels, and Horton spheres. The capacity of 16.6.3 Inspection Methods
the storage tanks ranges between 1000 and 75,000 m3 and In general, two types of inspection methods are used for
above. The quantity and quality of sludge generation varies health assessment of equipment or material:
depending on the products handled in the tank. The number 1. DT (destructive testing): This method is not used for an
of tanks is optimized and kept at a minimum because of operating refinery.
space limitations and the cost of the product handling 2. NDT (nondestructive testing): Most commonly used in
system through the tank. This necessitates the meticulous operating refineries. A brief description of the NDT
planning and tight cleaning and maintenance schedule of used in refinery inspection follows.
the tanks wherever required for maintenance. Cleaning
of tanks containing varieties of sludge is also a skillful job 16.6.3.1 Visual Inspection
and is generally handled by a mechanized system. The Visual inspection is a nondestructive examination method
tank cleaning schedule is maintained as per the inspection used to evaluate an item by observation for surface conditions
schedule of the tanks. and deformity. Direct visual examination may usually be made
when access is sufficient to place the eye within 24 in. of the
16.6 Inspection Practices surface to be examined and at an angle not less than 30° to
16.6.1 Scope the surface to be examined. Mirrors may be used to improve
The inspection function in the refineries is to protect assets the angle of vision, and aids such as magnifying lenses may
from deterioration and evaluation of equipment integrity for be used to assist examination. In some cases, remote visual
continued service. It provides technical support through trou- examination using visual aids such as mirrors, telescopes,
bleshooting and condition monitoring. Inspection activities boroscopes, fiber optics, cameras, or other suitable instru-
involves base data generation (design and operating data, ments may have to be substituted for direct examination.
metallurgy, thickness of the materials, metallurgical micro-
structure of critical high temperature equipment, etc.), health 16.6.3.2 Physical Measurement
assessment of the equipment, corrosion study based on the Physical measurement of equipment or its integral parts is
operating conditions, failure analysis, development of repair/ done to evaluate any dimensional change during operations,
welding procedures, metallurgical upgrade, and application fabrications, or installation. Normally, diameter [inner
of various nondestructive tests (NDTs)/destructive tests (DTs) diameter (ID)/outer diameter (OD)], thickness, grooves or pits,
for investigations, etc. Inspection is also responsible for cracks, etc., are measured using micrometers, calipers, pit
remaining life assessments of equipment, decision of plant gages, or such instruments. The measurement is compared
shutdown frequency, finalization of the inspection/equipment with the desired specifications for further actions.
replacement plan, and upkeep of documentation systems.
Inspection is to ensure that refinery operations are safe, 16.6.3.3 Dye Penetrant Test
smooth, and reliable for the intended company’s profit- The liquid penetrant examination method is an effective
ability and that they meet all statutory obligations of the means for detecting discontinuities, which are open to the
state/country. Inspection of equipment is usually performed in surface of nonporous metals and other materials. Typical
three stages, i.e., during manufacturing, precommissioning, discontinuities detected by this method are cracks, laps,
and in-service inspection. The discussion in this chapter will porosity, shrinkage areas, and laminations.
be limited to in-service inspection.
16.6.3.4 Magnetic Particle Testing
16.6.2 Inspection Philosophy Magnetic particle inspection is a method for locating surface
The in-service exposure of equipment causes deteriora- and subsurface discontinuities in ferromagnetic materials.
tion because of corrosion and environmental factors, and While testing a piece with hidden defects the magnetic par-
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inspection
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Chapter 16 n Refinery Inspection and Maintenance 409

is magnetized. The fine magnetic particles are attracted and liquid or gas under differential pressure. The test may be
are held in a place to indicate the defects in true form and done from an inside compartment to outside or vice versa.
orientation. A leak test is needed to check the integrity of fabricated
components and the system for pressure vessels, nuclear
16.6.3.5 Ultrasonic Testing reactors, electronic valves, vacuum equipment, gas contain-
Ultrasonic testing is a method that uses sound waves having a ers at pressure, etc. It is always measured as the leak rate
very high frequency beyond the audible range of the human with units as cubic centimetre per second.
ear. The properties of sound waves are very similar to light
waves in that they can be focused, reflected, and refracted. 16.6.3.13 Hydrostatic Test
This phenomenon is used in ultrasonic testing. Ultrasonic A hydrotest is the process of filling equipment such as a
pulses are transmitted to the specimen under examination, tank, vessel, exchanger tubes/shell, furnace/boiler tubes, and
and measurement is made of the time taken for the wave pipings with water/liquid at the appropriate pressure and
to reach the opposite surface or an intermediate flaw. This checking for any leakage. The test confirms the strength of
will locate the position of the flaw from the surface. This is the equipment as well as the integrity. In this test, properly
of particular advantage when only one surface is accessible. calibrated pressure gages are selected based on the complexi-
ties and size of the system/equipment as well as the pressure
16.6.3.6 Eddy Current Examination requirement. Normally, a minimum of two pressure gages
Eddy current inspection is based on the principles of are used that have ranges such that the pointer should
electromagnetic induction and is used to identify or differ- approximately be showing at the center of the test pressure
entiate between a wide variety of physical, structural, and on the dial.
metallurgical conditions in electrically conductive ferromag-
netic and nonferromagnetic metals and metal parts. The 16.6.3.14 In Situ Metallography
method uses attenuating currents in the radio frequency In situ metallography is an onsite evaluation of the metal-
range (50–5000 kHz) of the electromagnetic spectrum for lurgical degradation of high-temperature equipment. The
detection of surface and near-surface defects in the electri- metallographic kit contains a replica with portable hand
cally conducting materials. tools for taking a microstructure of the area of interest. The
sequential bank of the microstructure helps in deciding the
16.6.3.7 Radiography remaining life of the equipment vis-à-vis its reliability for
Radiography uses the penetrating capacity of ionizing radi- safe operation.
ation such as X rays and gamma rays to produce a shadow
of the internal condition of a job on a recording medium. 16.6.3.15 Thickness Loss Measurement
The recording of an area of interest on the film by ionizing Health of the equipment/piping is ascertained by wall thick-
radiation is known as radiography. ness measurement, and the operating life is decided based
on the remaining thickness and derived corrosion rate.
16.6.3.8 Creep Measurement
Gauging is a measurement of bulging within an allowable 16.6.3.16 Videoscopic Inspection
limit of furnace tubes to be decided for replacement beyond Inspection at inaccessible areas is done with this instrument.
the permissible limit.
16.6.3.17 Boroscopic/Fiberoscopic Inspection
16.6.3.9 Thermography Inspection at inaccessible areas is done with this instrument.
Infrared thermography is a temperature-based technique
that produces thermal images of an object on the basis of 16.6.3.18 Equipment for Health Assessment
the infrared radiation emitted by them. The equipment for refinery operations are broadly classified
into three categories.
16.6.3.10 Alloy Analysis 1. Static equipment
Positive material identification of the different metallurgy • Furnace
used in the refinery is done by an alloy analyzer to confirm • Power boiler
the actual materials used in the system against specifications. • Columns
The check confirms the different grade of alloys with the per- • Reactors
centage chemical compositions through assay. X-ray-based • Vessels
analyzers are currently used more than the previously used • Heat exchangers
gamma ray isotope-based instruments. • Tankages
• Horton spheres
16.6.3.11 Hardness Test • Stack/chimney
The hardness test is a measure of the ductility of CS/AS • Pressure safety valves/temperature safety valves
materials to confirm for intended use. It is used in alloy • Tank-mounted safety reliefs
steel components after heat treatment for desired services, • Rupture discs
also in Carbon Steel for stressed services like caustic/high • Expansion bellow
thickness (more than 19 mm) weldment etc. 2. Rotary equipment
• Compressors
16.6.3.12 Leak Test • Pumps
A leak test is the identification of a thorough defect in a wall • Blowers
of a tight assembly or component, pipe, or system using a
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• Turbines
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410 Petroleum Refining and Natural Gas Processing

3. Piping 16.6.4.2 Unplanned Inspection

• Process piping • Breakdown inspection and failure analysis
• Utility piping • Special inspection
• Valves and fittings • Operational/process requirement inspection
• Gaskets
16.6.4.3 Shutdown (Turnaround) Inspection
16.6.4 Inspection Criteria, Frequency, and The inspection is performed when the equipment/plant
Schedule is taken out of service during a planned unit shutdown. The
16.6.4.1 Broad Criteria Adopted for thorough internal and external inspection of all equipment
Inspection Frequency and piping systems is performed during the shutdown. All
• Corrosion/erosion properties of process fluid, chemicals,
parts of the equipment are thoroughly inspected and cor-
and catalysts. Rate of deterioration, remaining corro-
rective action is taken for safe run until the next planned
sion allowances, deterioration pattern, etc.
shutdown.
• Criticality of the equipment (cost, size, operational
A schedule of on-stream inspection for equipment and
criticality and dependency, material availability, etc.)
facilities is given in Table 16.2.
• Operational requirement
• Statutory requirement Table 16.2—On-Stream Inspection Schedule
The inspection frequency is decided based on the of Equipment and Facilities
criticality of the equipment and facilities and the inspec-
tion requirement, whether in-service inspection is possible, Daily Weekly Quarterly Annually
or if equipment/system isolation is desired. The inspection Heater Routine Casing Thermography
schedule is prepared accordingly. as per temperature
checklist
The following inspection programs are implemented in
the refinery: Reactor/ Routine as Skin
column/ per checklist. temperature
• Planned inspection: The equipment or system is inspected
vessel Temperature of lined
thoroughly after isolation from service during plant indicative of vessel
operation without compromising the plant efficiency. paint.
• On-stream inspection: It is performed when the Dosing Dosing at
equipment/plant is in service. It helps in determin- system individual
ing the extent of general damage and deterioration. It points
also helps in identification and rectification of unsafe Tanks Premonsoon
conditions arising out of faulty operation. The observa- inspection
tions form the basis to determine the extent of repairs/ Piping pH of Corrosion Impressed General
further investigations to be performed during the cooling probe in current condition of
shutdown. During on-stream inspection, monitoring of water jacketed measurement piping with
the critical operating parameters of rotary/static equip- system lines of cathodic supports.
protected
ment of process units and TPS/utilities is conducted, lines.
and immediate suggestions on corrective actions by Corrosion
operations, process, and maintenance teams is initiated. coupons.
The monitoring points are as follows:
• Furnace: COT, pressure drop across each pass,
skin temperature, presence of any hot spots, box 16.6.4.4 Heat Exchanger Inspection
temperature, burner flame condition, flue gas outlet Schedule
temperature, draft, falling of refractory, casing plate After the initial commissioning of the plant, the first
temperature, stack temperature, etc. inspection of the heat exchanger, cooler, and condenser
• Column: Overhead temperature should be above shall be performed as per the designers/licensor’s rec-
dew point temperature. ommendations or after 1 year of service, whichever is
• Exchangers: Pressure-temperature survey for iden- sooner. In general, the following frequency of inspection
tification of fouled exchangers/coolers affecting shall be adopted, which can be improved based on the
efficiency. equipment condition and inspection findings from time
• Vessels/accumulator: Accumulator or reflux drum to time.
pH/chloride/iron/copper, desalter salt content • Heat exchangers in corrosive service—2 years
upstream and downstream, adequacy of dosing • Heat exchangers in noncorrosive service—4 years
systems such as ahuralan, ammonia, caustic, • Condensers—2 years
demulsifier, etc. • Coolers—2 years
• Boiler: Boiler feed water pH/alkalinity/conductivity/
phosphate/silica/dissolved oxygen, superheater steam 16.6.4.5 Unit Shutdown Schedule
pH, superheater skin temperature, flue gas tempera- The inspection schedule is prepared by a joint decision of
ture, burner flame condition, etc.
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process/production and maintenance/inspection considering

• Cooling water quality: Flow, pressure tempera- all aspects as mentioned earlier and given in Table 16.3.
ture, pH, sulfur-reducing bacteria, Langlier index Tools used for inspection are given in Table 16.4. Instru-
(contributes to fouling), etc. ments used for inspection are given in Table 16.5 and spe-
• Crude analysis for presence of salt, sulfur, and TAN levels. cial instruments used are given in Table 16.6.
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Chapter 16 n Refinery Inspection and Maintenance 411

Table 16.3—Frequency of Unit Shutdown Table 16.6—Special Instruments

Maintenance and Inspection Alloy
Sr. No. Unit Frequency (years) Ferrite Meter Analyzer Digital Camera Binoculars
1. CDU/VDU/NSU 4 Ultrasonic leak Theodolite Internal rotary Tank bottom
detector inspection floor scanner
2. OHCU 4
system (IRIS)
3. HGU 4
Metallography Eddy current
4. RFCCU 2 kit tester/remote
5. CCRU 2 field eddy
current tester
6. DHDS 4
7. SRU 2 16.6.5 Major Inspection Points of Equipments
8. SWSU 2 16.6.5.1 Unfired Pressure Vessels (Columns,
9. ARU 2 Reactors, and Vessels)
Corrosion-prone areas in columns/reactors/vessels include
10. BBU 4
• Bottom head and shell of fractionators processing high-
11. MEROX 4 sulfur crude oils are susceptible to sulfide corrosion.
12. VBU 4 • Top heads and upper shell of distillation columns
13. BOILERS 1
are prone to chloride attack in the form of pitting
corrosion.
14. LUBE BASED PLANTS 4 • Fractionation and distillation column, knockout
15. WAX PLANT 4 drums, and reflux drums in the presence of wet H2S
(DEOILING UNIT) or cyanides are prone to cracks in welds and their
HAZ.
• Corrosion and erosion will take place in the shell
Table 16.4—Tools Used for Inspection directly opposite to the steam inlet and inlet streams.
Thermal ID/OD Calipers/ Go/No-Go • Corrosion occurs where two dissimilar metals are in
Chalks Vernier Calipers Gage Screw Gage close contact (cladded/uncladded zone).
Measuring Intrinsically safe Nonwashable Marker pens
tape/scale torch marking 16.6.5.2 Internal Inspection of Columns
chalks All parts of columns should be inspected for corrosion,
erosion, hydrogen blistering, cracking, and lamination.
Ball pein Files and emery Wire brush Inspection
hammer papers mirrors
Thickness measurements should be taken on heads, shells,
and nozzles to know the extent of deterioration. The top
Illuminated Dial gage Magnifying Weld gage dome and shell should be checked for pitting. The depth
mirror glass
of pits/grooves is measured by a pit depth gage. For wet
Surface Radiation survey Radiography Personal H2S, amine or caustic service, magnetic particle testing
profile gage meter film viewer radiation (WFMPT) is done in welded seams to detect surface cracks.
alarm meter Connected nozzles should be checked for internal corro-
Pocket Hydrometer Spirit level Wire gage sion. Supports for internals such as trays, baffles, screens,
dosimeter grids, piping, etc., should be visually checked. The general

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Buffing Heavy-duty Light-duty Scraper condition of internals such as trays and packing material
tools engraver drill should be checked for corrosion. The flash (feed) zone should
be thoroughly checked for erosion/corrosion of an impinge-
ment plate attached with the shell. The bottom dome and
Table 16.5—Instruments Used for Inspection shell near the draw-off nozzle are critically inspected for
pitting corrosion. The shell opposite of the steam injection
Portable High- Low-
nozzle should be checked for impingement.
Ultrasonic Temperature Temperature
Thickness Infrared Infrared
Meter Thermometer Thermo Hunter Thermometer 16.6.5.3 Inspection of Cladded Columns/
pH meter Pit gage Ultrasonic Dye-
Reactors
hardness tester penetrant kit Cladding protects the base metal from erosion/corrosion.
SS 410S, SS 316L, and Monel are some of the cladding
Magnetic Radiography Boroscope and Paint
materials used. Careful visual inspection of the lining is
particle arrangements fibroscope thickness
required for checking corrosion, erosion, bulging, etc. Light
inspection with dark room gage
kit hammer taps will identify corroded and cracked sections
of lining. Thickness measurements at designated locations
Holiday Optical Microscope Hardness
should be done to check the bonding of cladded metal with
detector densitometer tester
base metal. The junction of the cladded and uncladded zone
Vacuum should be checked for galvanic corrosion. Weld joints and
box testing HAZ should be checked for cracks. Pneumatic testing of
instrument
nozzle liners should be done.
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412 Petroleum Refining and Natural Gas Processing

16.6.5.4 Inspection of Gunite/Refractory makes them brittle at room temperature. All supports

Lined Vessels should be inspected for cracks.
Visually inspect gunite/refractory lined vessels to check for • Refractory lining (castables, CF blanket/module): The
spalling and cracks. Hot-spot locations are to be carefully refractory lining should be visually inspected for
checked. The lining is to be checked for bulging and loose- breakage, crumbling, and open joints. The clearance
ness by light hammer tapping. The thickness of the shell is in expansion joints of the lining should be checked
to be measured from outside. for deterioration from heat/debris. Clearance should
be filled with asbestos rope/ceramic fiber. After major
16.6.5.5 Statutory External Inspection of refractory repairs, it should be dried/cured properly
Vessels before commissioning.
• Inspection of all vessels should be done as per the existing • Furnace casing and accessories: Exposed parts of heater
rules of the country/state. casing should be visually inspected for signs of any
• External inspection should be conducted at least every damage, paint peeloff, etc. Casing should be inspected
5 years or whenever the opportunity is available. for thinning/perforation due to acidic flue gas corrosion.
• The frequency of inspection and hydrotest of boilers, Header boxes should be checked for warping because
pressure vessels, and Horton spheres should be reli- this leads to excess air in the heater resulting in addi-
giously performed per the Power Boiler Act and pressure tional fuel consumption. Proper alignment of burners is
vessel regulations of the country/state. essential because misaligned burners will lead to flame
impingement on radiation tubes and damage of burner
16.6.5.6 Fired Heaters housing. Burner tips should be checked for oxidation,
A fired heater is an internally insulated enclosure where the corrosion, and choking.
heat liberated by the combustion of fuels is transferred to • Thermocouple connections: Weldments of thermocouple
fluid contained in tubular coils. tips on radiation and convection tubes often crack in
service. The weld should be DP checked during every
16.6.5.6.1 Inspection Points for Furnaces planned inspection.
• External inspection of heater tubes:
• Check for sagging, bowing, and bulging. Sagging 16.6.5.6.2 Hydrostatic Testing
and bowing should not exceed 0.5 times the diameter A hydrostatic test should be performed in all heater tubes in
of the tube. Tubes should be checked for bulg- every planned shutdown. Hydrostatic test pressure should
ing, especially those that are subjected to flame be 1.5 times the maximum operating pressure (corrected for
impingement. If the increase in the diameter of temperature or shutoff pressure of pump). Testing should also
the tube at the bulge is 5 % or more, the tube is be done whenever tubes or fittings are replaced involving a
rejected. In the case of reformer tubes, the increase hot job in the system. During the test, inspection should be
in diameter is limited to 3 %. done for the heater to locate any leak. Austenitic stainless
• Check for oxidation, scaling, deposits, corrosion, steel tubes should be hydrotested with demineralized (DM)
cracks, and grooving. water or water having a chloride content less than 20 ppm.
• Check for roll leaks and plug leaks in the case of plug-
and header-type heaters in heavy oil/coker units. 16.6.6 Heat Exchanger
• All weld joints of heater tubes should be thoroughly The heat exchanger is equipment that is used for the heating
inspected for any crack or serious defects. or cooling of a fluid without intermixing.
• Magnetic particle inspection (MPI), DPT, radiog-
raphy, and ultrasonic flaw detection, etc., may be 16.6.6.1 Hydrotesting of Exchangers
used as per requirement. • All heat exchangers should be tested at 1.5 times the
• Wear/grooving at all tube support locations should design pressure when the shell or tube is new or any
be checked. major repair or replacement has been performed. The
• Ultrasonic thickness survey of tubes should be done periodic test pressure is calculated on the basis of 1.5
along the length to determine the metal loss and rate times the maximal operating pressure, pump shutoff
of deterioration. The outermost curvature of bends, pressure if directly connected to a pump, or safety valve
such as near the weld joint of the bend with tube, and test pressure mounted on the shell or tube side of the
upstream and downstream of tube weld joints, etc., heat exchanger.
are critical areas for corrosion/metal loss. • Wherever tube-side pressure is higher than shell-side
• In the convection section, the last few rows of pressure then it should be preferably tested at the tube-
tubes at the exit of flue gases should be checked side test pressure, provided that the design condition
for external corrosion due to the dew point of of the shell permits or vice versa.
flue gases. The accessible studded tubes should be • Pressure gages used in the hydrotest should be freshly
inspected for any sign of oxidation of studs due to calibrated and two gages of the same range should be
overheating or corrosion due to sulfurous deposits. used. The range of the pressure gage should be generally
• Tube supports: Tube supports are generally made of double the intended maximal test pressure, but in no case
25Cr-20Ni (HK-40) material. Tube supports are prone to should the range be less than 1.5 or more than 4 times
oxidation, corrosion, and cracking at high temperatures. the test pressure (30 % more than the test pressure).
Tube supports are prone to sigma phase formation due • DM water should be used for hydraulic tests if material
to prolonged exposure at high temperatures, which of construction is austenitic stainless steel.

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Chapter 16 n Refinery Inspection and Maintenance 413

• The duration of the test should not be less than 30 min, same as the tube metallurgy to avoid galvanic corrosion.
and a pressure gage should be installed at the highest The taper plug should have an included angle of 5.5° or less.
point. The plug dimension depends on the tube size and thickness.
A maximum of 20 % plugging is recommended to meet the
16.6.6.2 Procedure for Testing production efficiency.
Testing of the shell and tube exchangers is normally done in
three stages and with water as the test media. If the water 16.6.7 Storage Tanks
ingress in the equipment is not desirable, other suitable test 16.6.7.1 Inspection Frequency of Tanks
media should be selected (e.g., kerosine). Visual external inspection of all storage tanks should be
• Shell test: Shell tests facilitate detection of individual performed once a year. The detailed external inspection
tube leaks, if any. Soundness of shell weld joints/gasket along with a thickness survey of tanks should be conducted
joints is confirmed. In the case of floating head types, a as per the following unless otherwise guided by state statutory
separate test ring is required to conduct the shell test. In requirements (see Table 16.7).
the case of a roll leak, rerolling of the tube is done using
suitable expander and taking due care for overexpan-
sion. In the case of a tube leak, both of the tube ends are Table 16.7—Frequency of External
plugged with tapered plugs. It is desirable to remove the Inspection of Tanks
test fluid from the shell by air before doing the tube test. External Inspection
• Tube test: In this case tubes are pressurized and tested Interval (years)
under tensile stress. Here floating head gasket/channel With Without
cover gaskets are also tested. Tube leaks are detected, but Corrosion- Corrosion-
identification of individual tube tests is not possible here. Rate-Based Rate-Based
• Cover test: Pressurization of the shell side after boxing Sr. No Fluid Stored Assessment Assessment
up of the shell cover is done. The test pressure should 1. Crude oils, vacuum gas oil, 5 3
be equal to the shell test pressure. This facilitates total cycle oil, SKO, MTO, ATF,
exchanger component integrity for operation. HSD, gas oil, MS, naphtha,
• Individual tube test: This is done to discover the leaky benzene, toluene, ethanol,
tube in the bundle assembly by pressurizing each tube. MTBE, LDO, JBO, bitumen,
• Testing of box coolers: The coil should be pressurized lube oil, grease, industrial
and checked for leaks from the pipe, bends, gasket water, amines, etc.
joints, etc. The shell side should be tested by water fill. 2. Fuel oil, RCO, LSHS, vacuum 3 3
residue, slops, caustic
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16.6.6.3 Air Fin Fan Coolers 3. Acids (concentrated) 2 2

The segment should be pressurized hydraulically and
checked for leaks through plugs, rolls, and gasket joints and 4. Acids (dilute) 1 1
for any drop in pressure.
16.6.7.2 Internal Inspection
16.6.6.4 Breech Lock Exchangers All storage tanks should be subjected to detailed inspection
Having low alloy steel material of shell is susceptible to temper as per the following unless otherwise guided by state statu-
embrittlement. Hence, to avoid risk of brittle fracture due to tory requirements (see Table 16.8).
pressurization at ambient temperature, the metal temperature
of the shell side should be maintained at 93°C during test. The
skin temperature of the shell should be maintained through- Table 16.8—Frequency of Internal
out the test period. Pressure above 20 % of the design pres- Inspection of Tanks
sure should not be exceeded before attaining a temperature Internal Inspection Interval
of 93°C. Pressure should be raised to the shell side differential (years)
test pressure and maintained for 1 h. The shell side should be
With Without
pressurized to the shell test pressure and the tube side should Corrosion- Corrosion-
be simultaneously pressurized to the tube test pressure, ensur- Based Based
ing that at no time is the differential test pressure between the Sr. No Fluid Stored Assessment Assessment
shell and tube exceeded. Depressurization after testing should
1. Crude oils, fuel oil, RCO, Years 10
be done similarly. Pressure should be held for a minimum 1 h LSHS, vacuum residue, determined
before inspection. vacuum gas oils, cycle by corrosion
oil, SKO, MTO, ATF, HSD, rate and
16.6.6.5 Combined Feed Plate Heat Exchangers gas oil, MS, naphtha, integrity
Because the metallurgy of construction is austenitic stainless benzene, toluene, assessment
steel, DM water is used for a hydrotest. Due consideration ethanol, MTBE, LDO, or 15 years,
of maintaining differential test pressure is always simul- JBO, bitumen, lube oil, whichever is
taneously given during pressurization of the exchanger at grease, industrial water, lower
both sides as indicated above. caustic, amines
2. Slops Same as above 8
16.6.6.6 Tube Plugging 3. Acids (concentrated) Same as above 4
In the case of tube leaks, the tube is isolated with a plug at
4. Acids (dilute) Same as above 1
both ends. The metallurgy of the taper plug should be the
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414 Petroleum Refining and Natural Gas Processing

16.6.7.3 Inspection of Tank Roof • Acoustic emissions testing for online assessment of

Mountings storage tank floor
Tank mountings such as breather valves/P&V valves, relief • Magnetic floor testing for detecting top-side pitting and
valves, flame arresters, etc., should be ensured clean and under-side corrosion and holes on the tank floor
operable after every monsoon. Floating roof drains, shell • Low-frequency electromagnetic technique to map cor-
sealing, and emergency roof drains should be inspected rosion of tank bottom plate on product and soil sides
before every monsoon.
16.6.8 Off-Site Piping Types
16.6.7.4 Testing of Tanks • Above-ground—insulated/with heating coil/jacketed lines/
Bottom vacuum testing is performed using a metal testing uninsulated
box 6 in. wide by 30 in. long with a glass window at the top. • Underground
Suitable connections, valves, and gages should be provided
to maintain a partial vacuum of 3–5 psi (g) on the box. With 16.6.8.1 Internal Corrosion
the help of a soap solution, the bottom plate weldment • Uniform corrosion due to low/high pH
should be checked for any defect. • Localized corrosion in crevices, bends, etc.
• Preferential attack on weld
16.6.7.5 Hydraulic Testing of the Tank • Stagnant areas—in dead ends, etc.
Atmospheric tanks, which are designed to withstand less • Condensation/two-phase systems.
than 0.5 lb/ft2 (g) pressure over the static pressure of the • Internal lining damage
liquid contained in the tanks, are normally tested only by • Stress corrosion cracking
filling the tanks with water up to the curb angle in a fixed • High-temperature failures
roof and up to safe filling height in floating roof tanks. If • Hydrogen attack
water is not available, a carefully controlled air test using • Areas downstream of chemical injection points
an air pressure not exceeding 2 in. of water pressure may be • Naphthenic acid/polythionic acid corrosion
applied. In this case, a soap solution is applied on all sus-
pected areas of the tank for leak detection. Only fresh water 16.6.8.2 External Corrosion
or good quality water with a pH between 6 and 8.3 should • Corrosion under insulation
be used for testing. In the case of a longer duration of water • Soil-side corrosion of underground lines
holding time in the tank, suitable corrosion in inhibitors • Atmospheric corrosion—sulfurous/acidic environment
should be used. The hydrotest should be performed at a • Spillage/impingement
temperature of 4°C and above. Water filling rates should be • Corrosion at soil/air interface
decided based on the soil condition and tank design. In the
case of a stable foundation, the rate may be considered as 16.6.8.3 Stress-Related Failure
1.5 m/h. Only an approved filling rate holding time should • Overpressurization
be applied during testing. In the case of floating roof tanks, • Vibration—as in pump connected piping
a low filling rate of not more than 0.2 m/h should be used • Support failures—inadequate supporting system or
until the roof is floated. Thereafter, the filling rate may be stuck up
increased to the specified filling rate. For roof drains, after • Thermal stresses due to continuous wetting/drying in
inspection the pressure testing should be done at 3.5 kg/cm2. connected piping
For heating coils, after thorough inspection and necessary • Fatigue due to cyclic loading NDT techniques for
repair/replacements, coils should be hydrotested at 1.5 times piping
the operating pressure. • Ultrasonic thickness survey

16.6.7.6 Testing of Roof 16.6.9 Safety Mountings/Devices

Fixed roof tanks are tested by applying internal air pressure For equipment and process safety, the pressure vessels and
not exceeding the weight of the roof plates and applying storage tanks are provided with the following mounting:
a soap solution to the weld joints. Alternatively, vacuum • Pressure safety relief valve
testing can be performed. A floating roof should be tested • Temperature safety valve
for a smooth up and down movement. Stability of the roof • Rupture disc
should be checked by pouring water on the floating roof • Pressure and vacuum relief valve
equivalent to 10 in. of rainfall. The stability of the floating The routine testing and revision of these valves are
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roof of the tank should be checked both for single deck/ performed as per the inspection schedule, which is prepared
double deck by puncturing any two adjacent pontoon com- based on legal requirements, government acts, designer’s
partments with no water or live load. recommendations, and operational safety requirements.

16.6.7.7 Nondestructive Examination for 16.6.10 Inspection Documentation

Tank Inspection The following inspection recording and documentation
• Ultrasonic thickness measurement should be generated:
• Ultrasonic corrosion testing—automated ultrasonic • Drawings—one set of original as-built drawings.
scanning • Equipment data card.
• Ultrasonic shear wave testing to find out discrimination • Equipment data record card—to be prepared from
between lamination and inclusions equipment passport.

Copyright ASTM International

AST-MNL58-11-0801-016.indd 414 3/12/13 2:37 PM

Chapter 16 n Refinery Inspection and Maintenance 415

• History sheets—to be maintained chronologically. 2. Standards of Tubular Exchanger Manufacturers

• Inspection checklists for all categories of equipment Association.
and piping (includes on-stream, shutdown inspec- 3. ASME Pressure Vessel Code, Section 8.
tion, and external and internal inspections as per the 4. API 660, Shell and Tube Heat Exchanger for General
requirements). The checklist is to be religiously filled Refinery Services.
in for each equipment inspection. 5. BS 3274, Specification for Tubular Heat Exchangers for
• Inspection observation and record sheet—visual obser- General Purposes.
vations, dimensional checks, and thickness records are 6. API 653, Tank Inspection, Repair, Alteration, and
to be maintained. Reconstruction.
• Radiography films—to be stored for 5 years. 7. API 510, Pressure Vessel Inspection Code.
• All test certificates. 8. Indian Oil’s In-House Inspection Manual.
• Calibration chart. 9. ISO Standards for Vibration Measurement.
10. Vibration Charts from IRD Mechanalysis.
Suggested Reading 11. Indian Oil's Reliability Improvement Report, 2005.
1. API Guide for Inspection of Refinery Equipment, Chap-
ter 7, “Exchangers, Condensers, and Cooler Boxes."

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416 Petroleum Refining and Natural Gas Processing

Appendix 1—Preventive Maintenance Checklist for Centrifugal Pumps—Half-Yearly

Unit Frequency Half-Yearly

Equipment Type Centrifugal Pump Tag No.
Sap Order No. Date

Sr. Not Applicable/

No. Description of Job Done Not Done Remarks
1. Drain bearing oil, flush, and refill.
2. Examine oil bottle for leaks and proper operation.
3. Clean/replace oil filters of AOP and MOP.
4. Check gland leak and adjust.
5. Check mechanical seal and seal pot condition. Refill
the pot.
6. Check mechanical seal API flushing/quenching plan
condition. If required, clean the orifice, filter, and
cooler.
7. Check for proper locking of cartridge seal on position.
8. Check cooling water lines/lube oil lines for flow
and leaks.
9. Decouple and check coupling condition.
10. Check alignment and rectify, if needed (based on CM
observations.
11. Check coupling guard condition.
12. Check foundation bolts and tighten if necessary.
13. Clean suction strainer of pump. Repair if any.
14. Check piping and support/rectify.
15. Check that the surrounding area is clean.
16. Remarks (if any)/safety hazard.

Recording of Parameters after Pump Commissioning

Suction Discharge Motor Casing Temperature

Vibration Pressure Pressure Flow Amp. Bearing Temperature Noise Level
V H A
Special observation and status of the machine/online recording readings.

(Field Maintenance Engineer)

Special tools required: laser alignment tool, coupling spanner, set of cap screw keys, vibration meter, thermometer,
noise level meter.
Spares/consumables required: lube oil SS46, oil cup, coupling Shim pack set.

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Chapter 16 n Refinery Inspection and Maintenance 417

Appendix 2—Equipment Checklist for Plunger Piston Pumps/Diaphragm Pumps

Quarterly/Half-
Unit Frequency Yearly
Tag No. Sap Order No.

Sr. Not Not Applicable/

No. Description of Job Done Done Remarks
1. Check crank case oil condition; replace if required.
2. Check gear box oil condition; replace if required.
3. Check gland leak of slide valve, steam cylinder, and fluid
cylinder; adjust if necessary.
4. Check for any looseness and leakage of crank
case oil seal, isolator, deflector, etc.
5. Check for any abnormal sound/bearing sound/
valve knocking sound, etc.
6. Report safety hazard, if any.
7. Check alignment and rectify if needed.
8. Check function of NRV, PSV, pilot and slide valve.
9. Check lubrication of cylinder/plunger.
10. In addition to the above, the following checks should
also be performed during the half-yearly schedule:
11. Check cylinder and piston for wear.
12. Check/tighten or replace gland package.
13. Check force feed lubricator functioning
14. Check and clean/repair/replace suction and discharge
valves/valve seats.
15. Check foundation/foundation bolts for tightening.
16. Check discharge of pump.
17. Remarks (if any).

(Field Maintenance Engineer)

Special tools required: valve maintenance tool, DE spanner 80 mm, and gland tightening tool.
Spares required: Set of gland packaging, set of oil seals, stuffing box seal gasket.

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418 Petroleum Refining and Natural Gas Processing

Appendix 3—Vibration Severity Ranges in Accordance with ISO 2372

Range of Vibration
Severity in Velocity Examples of Quality Judgment for Separate Classes of Machines
Limits of Range,
mm/s Medium
Peak RMS Small Machines Class I Machines Class II Large Machines Class III Turbo-Machines Class IV
0.40 0.28
A
0.64 0.45
A
1.0 0.71
B
1.58 1.12
B
2.5 1.8
C B
4.0 2.8
C B
6.4 4.5
C
10.0 7.1
C
15.8 11.2 D
25 18 D
D
40.0 28 D
64.0 45
A A
A = Good
B = Usable (normal working condition)
C = Still acceptable
D = Unacceptable

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Chapter 16 n Refinery Inspection and Maintenance 419

Appendix 4—Guidelines for Types and Locations of Measurements and ISO Standards References
for Vibration

Standard
Machine Type Evaluation Parameters Sensor Type Measurement Locations Direction Reference Note
General rotating Displacement Noncontact sensor Shaft at each bearing Radial ISO 7919
machines 10–200 Part 1
Velocity Velocity sensor or Each bearing housing, Radial x
revolutions/s ISO 10816
accelerometer machine main structure and y,
(600–12,000 Part 1 a
axial z
revolutions/min)
•• Electric motors Acceleration Accelerometer Each bearing housing Radial x
•• Pumps and y
•• Turbines Enveloped acceleration, ESP™ Accelerometer Rolling element bearings Radial
Spike Energy ™, HFD™, BCU™ Accelerometer Rolling element bearings Radial
Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
Large steam Relative displacement Noncontact sensor Shaft at each bearing Radial ± 45° ISO 7919
turbines with fluid Part 2
Velocity Velocity sensor or Each bearing housing Radial x
film bearings ISO 10816
accelerometer and y
•• Power Part 2 b
generation Shaft axial position Noncontact Thrust collar Axial z
•• Mechanical drive sensor or shaft
•• Marine—usually rider
two separate Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
Small industrial Relative displacement Noncontact sensor Shaft at each bearing Radial ± 45° ISO 7919
steam turbines with Part 3
Velocity Velocity sensor or Each bearing housing Radial x
fluid film bearings ISO 10816
accelerometer and turbine hosing and y
Part 3
Shaft axial position Noncontact Thrust collar Axial z
sensor or shaft
rider
Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
Turbines with Velocity Velocity sensor or Each bearing housing Radial x ISO 10816
rolling element accelerometer and turbine hosing and y Part 3
bearings Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
Large and medium Relative displacement Noncontact sensor Shaft at each bearing Radial ± 45° ISO 7919
industrial gas Part 4
Velocity Velocity sensor or Each bearing housing Radial x
turbines with fluid ISO 10816
accelerometer and turbine hosing and y
film bearings Part 4
Shaft axial position Noncontact sensor Thrust collar Axial z
or shaft rider
Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
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Large generator Relative displacement Noncontact sensor Shaft at each bearing Radial ± 45° ISO 7919 c
with fluid film Part 2
Velocity Velocity sensor or Generator housing Radial x
bearings ISO 10816
accelerometer and y
Part 2
Shaft axial position Noncontact sensor Shaft end Axial z
(if not rigidly coupled to or shaft rider
deriver)
Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
Large pumps with Relative displacement Noncontact sensor Shaft at each bearing Radial ± 45° ISO 7919 d
fluid film bearings Part 3 &
Shaft axial position Noncontact sensor Axial z
•• Boiler feed Part 5
or shaft rider
•• Circulating ISO 10816
•• Process Phase angle reference and Optical or Shaft Radial Part 3 &
RPM mechanical sensor Part 5
(Continued )

Copyright ASTM International

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420 Petroleum Refining and Natural Gas Processing

Appendix 4—Guidelines for Types and Locations of Measurements and ISO Standards References
for Vibration (Continued)

Standard
Machine Type Evaluation Parameters Sensor Type Measurement Locations Direction Reference Note
Medium and small Relative displacement Noncontact sensor Shaft at each bearing Radial ± 45° ISO 7919 d
pumps with fluid Part 3
Shaft axial position Noncontact sensor Thrust collar Axial z
film bearings ISO 10816
or shaft rider
Part 3
Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
Medium and small Velocity Velocity sensor or Each bearing housing Radial x ISO 10816 d
pumps with rolling accelerometer and turbine hosing and y Part 3
element bearings Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
Vertically mounted Relative displacement Noncontact sensor Shaft at each bearing Radial ± 45° ISO 7919
pumps Part 5
Shaft axial position Noncontact sensor Thrust collar Axial z
•• Reactor coolant ISO 10816
or shaft rider
Part 5
Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
Large electric Relative displacement Noncontact sensor Shaft at each bearing Radial ± 45° ISO 7919
motors with fluid Shaft axial position Noncontact sensor Thrust collar Axial z Part 3
film bearings or shaft rider ISO 10816
Part 3
Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
Medium and small Velocity Velocity sensor or Each bearing and motor Radial x ISO 10816
motors with rolling accelerometer housing and y Part 3
element bearing Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
Compressors Relative displacement Noncontact sensor Each bearing, pinion Radial ± 45° ISO 7919
•• Package housing, and ball gear Part 3
centrifugal shaft ISO 10816
(four-poster), Velocity Velocity sensor or At each gear mesh Radial x Part 3
with fluid film accelerometer and y
bearings and
rigid housing Phase angle reference and Optical or Each shaft Radial
RPM mechanical sensor
Compressors Relative displacement Noncontact sensor Shaft at each bearing Radial ± 45° ISO 7919 e
•• Centrifugal Shaft axial position Velocity sensor or Thrust collar of shaft Radial x Part 3
process accelerometer end and y 10816
Part 3
Phase angle reference and Optical or Shaft Radial
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RPM (if driving through a mechanical sensor

gear box)
Compressors Relative displacement Noncontact sensor Piston rod and each Axial z and ISO 7919
•• Reciprocating bearing housing radial ± 45° Part 6
with fluid film Velocity Velocity sensor or Rod housing Radial x ISO 10816
bearings accelerometer and y Part 6

Position reference Optical or One drive rod or piston Radial

mechanical sensor at TDC, or crank shaft
Compressors Relative displacement Noncontact sensor Shaft at each bearing Radial ± 45°
•• Screw type with Shaft axial position Noncontact sensor Thrust collar Axial z
two interlocking or shaft rider
shafts, fluid film
bearings Phase angle reference each Optical or Each shaft Radial
shaft mechanical sensor
Compressors Velocity Velocity sensor or Bearing caps and Radial x ISO 10816
•• Screw type with accelerometer compressor housing and y Part 6
two interlocking Phase angle reference each Optical or Each shaft Radial
shafts, rolling shaft mechanical sensor
element bearings

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Chapter 16 n Refinery Inspection and Maintenance 421

Standard
Machine Type Evaluation Parameters Sensor Type Measurement Locations Direction Reference Note
RIC engines, Displacement Noncontact sensor, Bearing caps, main Axial z and ISO 7919
or reciprocating velocity sensor, or body, attached radial ± 45° Part 6
internal combustion accelerometer components ISO 10816
machines, rolling Part 6
Velocity Velocity sensor or Bearing caps, main body Radial x
element bearing accelerometer and y
Acceleration Accelerometer Bearing caps, main Axial or
body, cylindrical heads radial
Gears—large with Relative displacement Noncontact sensor Shaft at each bearing Radial ± 45°
fluid film bearings Velocity Velocity sensor or Bearing caps and gear Radial x
accelerometer case and y
Shaft axial position Noncontact sensor Shaft ends Radial z
or shaft rider
Gears—with rolling Velocity Velocity sensor or Bearing caps and gear Radial x
element bearing accelerometer housing and y
Fans—large radial Relative displacement Noncontact sensor Bearing housing casing Radial ± 45° ISO 7919
with fluid film Part 3 f
Shaft axial position Noncontact sensor Thrust collar of shaft Radial z
bearings ISO 10816
or shaft rider end
•• Cooling tower Part 3
fans Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
Fans—medium and Velocity Velocity sensor or Each bearing cap and Radial x ISO 10816
small with rolling accelerometer fan housing and y Part 1
element bearing ISO 10816
Part 1
Centrifuge Relative displacement Noncontact sensor Shaft at each bearing Radial ± 45°
(if accessible)
Velocity Velocity sensor or Housing Radial x
accelerometer and y
Shaft axial position Noncontact sensor Thrust collar Axial z
or shaft rider
Phase angle reference and Optical or Shaft Radial
RPM mechanical sensor
Pulp refiners Relative displacement Noncontact sensor Shaft at each bearing Radial x
and y
Velocity Velocity sensor or Bearing caps Radial x
accelerometer and y
Phase angle reference and Noncontact sensor On shaft ends Radial z
RPM or shaft rider

Notes: aAlso refer to specific machine entry in table.

b
Orthogonal measurements at 45° are recommended for condition monitoring. x and y locations are acceptable.
c
Measuring both the DC displacement and the dynamic displacement is always a recommended practice. It is more important for hydroelectric turbines
because of the relatively larger radial bearing clearances.
d
Pump vibration varies significantly with operating condition, and ideal operation at the best efficiency point (BEP) will have the least vibrations.
Operating continuously at a point other than the BEP will produce increased vibrations.
e
If not directly coupled, two key references are required.
f
On large axial flow fans, if the bearing housings and drive shafts are not accessible, accelerometer vibrations on the housing, x and y direction, are required.

The above appendix gives guidelines for types and locations of measurement with respect to ISO standards. Depending
on the level of vibration present in the equipment and its characteristics, it is possible to indicate likely reasons that might
be inducing vibration. The following are the major factors that induce vibration in equipment:
• Unbalance
• Misalignment
• Mechanical looseness
• Bearing problems
• Gear problems
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• Resonance problems
• Rotor rubbing
• Flow-induced vibration
• Electrical problems
• Belt drive problems
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422 Petroleum Refining and Natural Gas Processing

Appendix 5—Fired Heater Inspection Checklist

Unit: Date:
Equipment no.:
1. TUBE AND FITTINGS INSPECTION ii) Visual inspection of welding:
a) RADIATION iii) DP of weld joint:
Visual inspection
i) Tube condition:
4. REFRACTORY LINING INSPECTION
ii) Fittings condition:
a) Radiation
iii) Weld joint:
i) CF lining:
iv) Tubes seating on support:
ii) Castable:
Thickness check
b) Convection
i) Tube:
i) CF lining:
ii) Fittings:
ii) Castable:
b) CONVECTION
c) Floor
Visual inspection
i) Castable:
i) Tube condition:
ii) Bricks:
ii) Fittings condition:
d) Stack
iii) Weld joint:
i) Castable:
iv) Tubes seating on support:
5) MISCELLANEOUS ATTACHMENTS
Thickness check
a) Explosion doors:
i) Tube:
b) Dampers:
ii) Fittings:
c) Flue gas ducts:
c) SUPERHEATER COILS
d) Header box:
Visual inspection
e) Peephole (field of view):
i) Tube condition:
f) Inspection doors:
ii) Fittings condition:
6) BURNERS
iii) Weld joint:
a) Numbers installed:
iv) Tubes seating on support:
b) Condition:
Thickness check
7) AIR PREHEATER
i) Tube:
a) Duct lining and insulation:
ii) Fittings:
b) Glass module:
2. TUBE SUPPORTS INSPECTION
c) Cast module:
a) Radiation
8) SOOT BLOWERS
i) Tube hangers:
9) EXTERNAL PAINTING
ii) Guides:
10) FOUNDATION
iii) Spigots:
11) STRUCTURES
b) Convection AND Steam Coils
12) HYDROTEST
i) Tube sheets:
a) Date:
3. THERMOCOUPLES
b) Media:
a) Radiation
c) Pressure
i) Number of thermocouples:
13) STRESS RELIEVING
ii) Visual inspection of welding:
14) RADIOGRAPHY
iii) DP of weld joint:
15) REMARKS
b) Convection
i) Number of thermocouples: INSPECTED BY:
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Chapter 16 n Refinery Inspection and Maintenance 423

Appendix 6—Pressure Vessels Inspection Checklist

Unit: Date:
Equipment no.:
Service:
REASON FOR INSPECTION
Shutdown
On-stream
Breakdown
1) INTERNAL INSPECTION
a) Top zone
i) Scaling nature
ii) Dome
iii) Shell
iv) Welding
v) Nozzle welding
vi) Internals
vii) Spouts and counterspouts
b) Middle zone
i) Scaling nature
ii) Shell
iii) Welding
iv) Nozzle welding

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v) Internals
vi) Spouts and counterspouts
vii) Impingement plate
c) Bottom zone
i) Scaling nature
ii) Shell
iii) Welding
iv) Nozzle welding
v) Steam coils
2) EXTERNAL INSPECTION
a) Foundation and foundation bolts
b) Insulation
c) External corrosion
d) Ladder and staircase
e) Nozzle flanges
f) Bosses and nipples
g) Grounding connections
h) Testing nipple and liners on nozzle
3) THICKNESS SURVEY OF EQUIPMENT
INCLUDING ALL NOZZLES Yes/No
4) CONDITION OF INTERNAL LINING
5) REPAIR, IF ANY
6) CORROSION COUPONS Yes/No
7) REMARKS

INSPECTED BY:

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424 Petroleum Refining and Natural Gas Processing

Appendix 7—Heat Exchanger Inspection Checklist

Date:
Unit: Equipment no.: Service:
Brief description of last inspection
Whose requirement IP/PN
Bundle pullout Yes/No
Agency Contractor/MRS
Cleaning Mechanical/chemical/both mechanical and chemical
No. of tube Total
Already plugged
Recent plugging
Total plugging
Shell
Shell nozzles
Channel
Channel nozzles
Painting
Tubes
Baffle
Floating head
FH seat
Anodes
Hydraulic testing
Shell (kg/cm2): Tube (kg/cm2):
Recommendations

INSPECTED BY:
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Chapter 16 n Refinery Inspection and Maintenance 425

Appendix 8—Storage Tank Inspection Checklist

Tank No. Service: Inspection Date:
Type of inspection: External/internal
OBSERVATIONS OF EXTERNAL INSPECTION

1.0 Tank Pad Foundation Y/N Observations 4.4 Roof vents condition is
satisfactory.
1.1 Foundation pad is free from
cracks settlements/erosion/ 4.5 Foam system/hydrant lines
vegetation growth etc. condition is satisfactory.
1.2 No voids found between annular 5.0 Floating Roof Y/N Observations
plate extensions and foundation 5.1 Roof is free from corrosion
surface. patches and painting condition is
1.3 Foundation slope is satisfactory to satisfactory.
avoid water stagnation. 5.2 Roof plates weld joints are found
1.4 Tank is free from abnormal/ satisfactory without any sweating/
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uneven settlement. leaks.

2.0 Annular Plate Extension Y/N Observations 5.3 Roof is free from patch plates/cold
weld repairs.
2.1 Annular plate extensions are
free from corrosion, pitting, and 5.4 Thickness readings of roof plates
scales, and the painting condition are satisfactory.
is satisfactory. 5.5 Pontoon compartments are free
2.2 Annular plate thickness readings from leaks/sweating/corrosion and
are satisfactory. painting condition is satisfactory.
3.0 Shell Plates (External) Y/N Observations 5.6 Primary seals are in satisfactory
condition (neoprene sheet and
3.1 Shell plates are found free from
foam).
corrosion patches, pitting, and
scales, and the painting condition 5.7 Condition of weather shrouds was
is satisfactory. satisfactory.
3.2 Shell plates are free from 5.8 Deck support legs and pipe sleeves
abnormal dents/buckles. are in satisfactory condition.
3.3 Shell plates are free from 5.9 Main drain including sump
sweating/leaks/cold weld/repairs/ and NRV/emergency drains are
patch plates. checked and conditions are okay.
3.4 Reinforcement pads are in 5.10 Roof drain valve was found
satisfactory condition at opened.
nozzles. 5.11 Condition of rim vents/PV valves/
3.5 Wind girders are found in breather valves was satisfactory.
satisfactory condition without 5.12 Sample/dip hatch pipe condition
corrosion patches and sagging. and rollers/brass sleeves are in
3.6 Supports for connected piping/ satisfactory condition.
nozzles are in satisfactory 5.13 Rolling ladder and its runway
condition without unduly condition are satisfactory.
stressing the shell plates.
5.14 Condition of foam dam plates are
3.7 Shell plates, nozzles, steam coil satisfactory.
nozzles, manholes, cleanout
doors, etc., thickness readings are 6.0 Appurtenances/Attachments Y/N Observations
satisfactory. 6.1 Condition of earthing are
3.8 Condition of foam/sprinkler lines satisfactory.
and foam deflectors plates was •• Between floating roof and
satisfactory. ladder
•• Between rolling ladder and
4.0 Cone Roof Plates (Fixed Roof) Y/N Observations shell
4.1 Roof is free from corrosion •• Between shell and earth
patches and painting condition is 6.2 Condition of insulation and
satisfactory. claddings are checked and found
4.2 Thickness readings of roof plates satisfactory in insulated tanks.
are satisfactory. 6.3 Sealing of insulation around
4.3 Flame arrestor condition (if manways and nozzles are
provided) is satisfactory. satisfactory.
(Continued )
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426 Petroleum Refining and Natural Gas Processing

Appendix 8—Storage Tank Inspection Checklist (Continued)

OBSERVATIONS OF INTERNAL INSPECTION

6.4 Condition of staircase, handrails, 7.15 Roof support column and its
etc., and paintings are satisfactory. reinforcement pad (if provided)
6.5 Condition of siphon drains was are in satisfactory condition.
satisfactory. 7.16 Structural under roof plates viz.
6.6 Condition of cleanout doors was rafters, fasteners, gussets, etc.,
satisfactory. are checked and found to be
satisfactory.
7.0 Bottom Plates and Internals Y/N Observations
7.17 Condition of Sacony mixture
7.1 Bottom plates’ painting condition
(nozzles/supports/pipe) is
is satisfactory.
satisfactory.
7.2 Shell plates’ painting condition is
7.18 Steam coils (if any) are surveyed
satisfactory.
for thickness, supports, and
7.3 Roof plates and structure painting hydraulically tested at 13.5 kg/cm2.
condition is satisfactory. Condition found satisfactory.
7.4 Condition of outer rim of
pontoons including painting (in
fixed roof tanks) was satisfactory 8.0 Details of Tanks Nozzles/Manholes/Clean Outdoors
and no appreciable corrosion/ Nozzle Identity SIZE/NB Observed Thickness
pitting was observed.
8.1 Inlet
7.5 Condition of weld seams in first
two courses (horizontal and vertical 8.2 Outlet
joints) is found satisfactory without 8.3 Roof drain
grooving, pinholes, and cracks.
8.4 Siphon drain 1.
7.6 Shell plates are free from closely 2.
located deep pitting.
8.5 Shell manway 1.
7.7 Shell plates are free from patch 2.
plates/cold weld repairs.
8.6 Recirculation line
7.8 Shell to bottom plate joint is
8.7 Jet mixture 1.
found satisfactory.
2.
7.9 Edge settlement is within the
8.8 Temperature gage
reasonable limit.
8.9 Foam connections 1.
7.10 Bottom plate weld seams are in
2.
satisfactory condition.
8.10 Steam coils 1.
7.11 No appreciable corrosion/pitting
2.
on bottom plates was observed.
8.11 Cleanout doors 1.
7.12 Bottom plates are found without
2.
patch pipes/cold weld repairs.
8.12 Any other nozzles
7.13 Bottom plate thickness readings
were satisfactory and no appreciable
thickness loss was observed. 9.0 Any Other Specific Observations, If Any
7.14 Swivel joints and their piping
conditions were satisfactory. Swivel
joint revisioning and hydrostatic INSPECTED BY:
testing was done at 3.5 kg/cm2 and
was found to be satisfactory.
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Chapter 16 n Refinery Inspection and Maintenance 427

Appendix 9—High-Pressure Boilers Checklist

Date:
Visual INSPECTION
1) STEAM DRUM
• Internal:
• External:
2) MUD DRUM
• Internal:
• External:
3) ECONOMIZER COILS
4) SUPERHEATER ASSEMBLIES
• Platen superheater
• Final superheater
5) DESUPERHEATER (DESH)
6) SUPPLY TUBES
7) WATER WALL TUBES
8) WATER WALL HEADERS
9) RISER TUBES
10) SATURATED LINKS
11) REGENERATIVE PREHEATER
12) STEAM COIL PREHEATER
13) DUCT EXPANSION BELLOWS
14) SOOT BLOWERS
15) SAFETY VALVES
16) SKIN THERMOCOUPLES
17) BURNERS
18) ALLOY ANALYSIS
19) RADIOGRAPHY
20) STRESS RELIEVING
21) REFRACTORY
22) THICKNESS SURVEY
23) PAINTING
24) SAFETY VALVE FLOATING
25) HYDROTESTING

INSPECTED BY:

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428 Petroleum Refining and Natural Gas Processing

Appendix 10—Pipeline Inspection Checklist

PIPELINE IDENTITY:
Inspection Date:

SN Checklist Points Y/N Observations SN Checklist Points Y/N Observations

PHYSICAL CONDITION CORROSION AND ITS PROTECTION
1.1 Ground clearance of the piping 4.1 Painting condition of the
is adequate. aboveground pipeline
throughout its length found
1.2 Pipeline is free from any visible
satisfactory.
sweating/leakage.
4.2 Pipeline outer surface are
1.3 Pipeline is free from
found without deep pitting/
dents, cracks, scratches,
corrosion attack, etc.
impingements, and any
mechanical damages. 4.3 Check for wrapping/coating of
pipelines crossing roads/dykes/
1.4 Pipe is accessible for inspection
boundary walls and also for
under the culvert.
proper sealing of the sleeve
1.5 Pipeline route is clear without pipes at ends.
vegetation in aboveground
THERMAL INSULATION
portion.
5.1 Insulation/cladding of pipe is
THICKNESS SURVEY
found satisfactory.
2.1 Thickness survey conducted
5.2 Steam tracer lines are free
for aboveground portion.
from leakage.
The results are satisfactory
to continue to operate the LPDS & OTHER TAP-OFF FITTINGS
pipeline (attach thickness 6.1 All branch pipelines including
survey). tap-off points for instruments
2.2 Thickness survey conducted and sampling points are
in underground piping on surveyed and general
sample basis after removal of conditions found satisfactory
wrapping/coating and found without cracks/leakage.
satisfactory. 6.2 Blinds used at the dead ends
SUPPORTS are satisfactory.
3.1 Condition of supports (with 6.4 All flange joints are leak
respect to damage/distortion free.
in concrete pedestal, roller GI 6.5 Expansion joints are found to
pipe, sinking of support, etc.) is be free of leaks.
satisfactory.
7.0 Any other observations
3.2 Saddle plates provided at the
pipe supports are welded all
along the periphery to prevent INSPECTED BY:
water ingress.
3.3 Piping is anchored properly
near the expansion loops.

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Chapter 16 n Refinery Inspection and Maintenance 429

Appendix 11—On-Stream Inspection Format of Cdu/Vdu/Nsu

DATE:
THROUGHPUT: m3/hr

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TYPE OF CRUDE: LS/HS
REMARKS/AREAS OF CONCERN:
SKIN TEMPERATURE.

Visual
Design Limit Maximum Skin Condition of
Furnace 0
C Temperature (0C) Furnace
Crude
heater
Vacuum
heater
NSU
heater

Heater Draft: (mm of WC): CDU heater:

VDU heater: NSU heater:
COLUMN TOP TEMPERATURE
ATMOSPHERIC COLUMN TOP TEMPERATURE–
LIMIT: —/— °C (Min)
VACUUM COLUMN TOP TEMPERATURE–
LIMIT: —/— °C (Min)
pH AND CHLORIDE OF SOUR WATER

Chloride (Limit: Fe (Limit:

<20 ppm) <1 ppm)
Overhead pH (Limit: (previous Day’s (Previous Day’s
Accumulator 5.5–6.5) Result) Result)
-VV-01

DESALTER Yes/No Water injection m3/hr

OPERATING:
DPC 1201/1202 kg/cm2 Temperature: °C
SALT CONTENT OF CRUDE:
Pre-Desalter: Post-Desalter (Limit: < 0.5 ptb):
CHEMICAL DOSING PUMPS:
CORROSION INHIBITOR: Yes/No
AMMONIA: Yes/No
NEUT. AMINE: Yes/No
DEMULSIFIER: Yes/No
CAUSTIC: Yes/No
TSP: Yes/No

INSPECTED BY:

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430 Petroleum Refining and Natural Gas Processing

Appendix 12—On-Stream Inspection Format of Ccru

DATE:
THROUGHPUT, m3/h (HYD./REFORMER):

A) HEATERS C) pH VALUES

Arch. Vessel No. Ph Values Remarks

Temperature Flame
Observed Limit
Skin Temperature (°C) °C Condition
-V-102
Heater Cot Pass Pass Pass Pass Design
No. °C 1 2 3 4 Limit -V-104
-F-101 -V-701
-F-102
-F-204 D) STATIC EQUIPMENT UNDER MAINTENANCE:
E) REMARKS/AREAS OF CONCERN:
STACK TEMPERATURE 1. IFP HEATERS:
2. NON-IFP HEATERS: INSPECTED BY:
B) COLUMNS

Top Temperature °C Inhibitor Dosing

Column No. Observed Limit (Y/N)
-C-101
-C-201

Appendix 13—On-Stream Inspection Format of Vbu

THROUGHPUT (m3/h): DATE:

A) HEATER C) Ph VALUE

Skin Temperature °C Ph Values

Observed Flame Imp. Tag No. Recorded Limit Remarks
Tag No. Cot (Max) Limit (Y/N) -V-01
-F-01
D) STATIC EQUIPMENT UNDER MAINTENANCE:
B) COLUMN E) REMARKS:

Top Temperature °C INSPECTED BY:

Inhibitor Dosing
Tag No. Observed Limit (Y/N)
-C-01

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Chapter 16 n Refinery Inspection and Maintenance 431

Appendix 14—On-Stream Inspection Format Rfccu

THROUGHPUT (m3/h) DATE:

1. FEED HEATER 4. FLUE GAS COOLER (07-LW-00-001): Generation: T/h

Skin Temperature, °C Box Temperature, °C Bfw Blowdown

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T. No. Pass 1 Pass 2 Limit Radiation Parameter Limit Observed Parameter Limit Observed
Arch pH >9 Condition <2500
Stack (mmho/cm)
Silica <.02 Silica <10
Flame Condition: COT: Draft: mm WC
(ppm) (ppm)

2. RR–SECTION TEMPERATURE Residual >0 PO4 (ppm) <15

N2H4
Equipment Limit, °C Dense Bed, °C Dilute Phase, °C
RG-1
CHEMICAL DOSING:

RG-2
Trisodium
Morpholene: Y/N Hydrazine: Y/N Phosphate: Y/N
3. MAIN FRACTIONATING COLUMN
1. STATIC EQUIPMENT UNDER MAINTENANCE:
Top Temperature (°C): Overhead pH: 2. REMARKS:

INSPECTED BY:

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432 Petroleum Refining and Natural Gas Processing

Appendix 15—On-Stream Inspection Format (Ohcu/Hgu/Dhds)

A. OHCU DATE:

1. FURNACE

Furnace F-01 F-501 F-502 F-503

Max Skin Temperature

2. COLUMN TOP TEMPERATURE

Fractionator Stripper

3. AHURALAN INJECTION/WATER INJECTION (YES/NO)

Debutanizer DM Water In Reaction

Column Stripper Column System

4. STATIONARY EQUIPMENT UNDER MAINTENANCE:

REMARKS
B. HGU
1. REFORMER HEATER

Skin Temperature (Max Limit– °C)

Cell T# 1 T#15 T#30 T#45 T#60 T#75
South-AB
North-CD

2. COLD COLLECTOR SKIN TEMPERATURE (MAX

LIMIT– °C):
3. CHEMICAL DOSING (MORPHOLINE/HYDRAZINE/
TSP) YES/NO
4. pH (LIMIT): STEAM DRUM
DEAREATOR
5. STATIONARY EQUIPMENT UNDER MAINTENANCE:

REMARKS
C. DHDS
1. FEED HEATER SKIN TEMPERATURE (MAX
LIMIT– °C):
2. CHEMICAL DOSING (CORROSION INHIBITOR)
YES/NO

Stripper Column Stabilizer Column

3. STATIONARY EQUIPMENT UNDER MAINTENANCE:

REMARKS:

INSPECTED BY:
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Chapter 16 n Refinery Inspection and Maintenance 433

Appendix 16—Cpp On-Stream Inspection Report Format

Date:

Raph Air Raph F Gas

Load Flame
Unit (T/H) Condition Remarks
B#1
B#2
B#3
HRSG

Equipment/
Stream Parameter Limit Observed Remarks
pH 8.8–9.2
Dissolved O2 5 ppb (max)

Silica 0.01 ppm

(max)
Conductivity 0.3 μó/cm
(max)
Residual 0.01–0.02
hydrazine ppm

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Drum water pH 9.2–10.0
B1/B2/B3 Silica 2.0 ppm
(max)
Conductivity 200 μó/cm
(max)
Residual 5–20 ppm
phosphate
Superheated Silica 0.02 ppm
steam (max)
Chemical Hydrazine Yes/No
dosing Morpholine Yes/No
Phosphate Yes/No
Note: Any static equipment failure/under maintenance:

INSPECTED BY:

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434 Petroleum Refining and Natural Gas Processing

Appendix 17—On-Stream Inspection Format of Sru Block

Date:

A) BBU (U-10)
HEATER (10-F-001)

Max Skin Temperature Box Temperature COT Flame

(Limit–°C) (°C) (°C) Condition

Static equipment under maintenance:

B) BBU (U-10)
COLUMNS

Top Temperature °C Remarks

Limit Observed
-C-01
-C-02

• pH VALUES

Refinery SWS OHCU SWS

Limit (6.0–7.0) Limit (6.0–7.0)
-V-01 Sour -C-01 Stripped -V-02 Sour -C-03 Stripped
Water Water Water Water

Static equipment under maintenance:

C) ARU (U-21)
COLUMN (21-C-02)

Inhibitor Dosing
Top Temperature (°C) (Yes/No) Remarks
Limit Observed

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Static equipment under maintenance:
D) SSRU (U-44)
• MCC Box
• Stack Top Temperature (Limit > 190 °C)
E) SRU (U-22)

INSPECTED BY:

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Chapter 16 n Refinery Inspection and Maintenance 435

Appendix 18—Special Tools/Gadgets Used In Mechanical Maintenance

Figure 16.8—Hydraulic torque wrench.

Figure 16.9—Scissor lift.

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Figure 16.10—The bundle puller.

Source (Figures 16.8–16.10): Maurya, S.L., Ghosh, A., Paranjape, D.B., and Kacker R., “Indian Oil's Reliability Improvement Report (Refineries Division),” Indian
Oil Corporation Ltd., New Delhi, India, 2005.

Copyright ASTM International

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17
Corrosion Inspection and Control in Refineries
Jorge L. Hau1

17.1 Introduction units, calcium and magnesium chloride salts present in

Crude oil by itself should not be corrosive to metals, but when the crude oil hydrolyze to form hydrogen chloride (HCl)
extracted, it contains water, sulfur-organic compounds, nitro- gas, which, in the presence of moisture and water, forms
gen compounds, salts, organic acids, and other contaminants corrosive hydrochloric acid. Sulfur and organic acids also
that make it corrosive to metals and alloys used to manufac- thermally decompose in the furnace and form hydrogen
ture equipment and piping. The use of high temperatures sulfide (H2S) and carbon dioxide (CO2). It has been stated
and pressures in oil refining processes can create particular that organic acids can also form by thermal degradation of
corrosive environments. Additions made to the process as crude oil components such as naphthenic acids. All these
raw material or as catalysts can also create particular cor- acid gases separate from the liquid and go to the top of the
rosive environments to these metallic materials. Thus, the distillation tower and the overhead system, together with
materials of construction of pressure vessels, heat exchangers steam, naphtha, and light end products (butanes, propane,
shell and tube bundles, air coolers, piping, piping acces- ethane, and methane). At the typical crude unit overhead
sories, column trays, packing material, and other pieces temperatures of 90 °C to 180 °C, the overhead stream
of equipment can be subjected to a rather large variety of becomes corrosive when water condenses and dissolves
corrosion and other damage mechanisms. If not properly these acid gases. Presence of other contaminants such as
recognized and managed, they can lead to increased risk oxygen, ammonia (NH3), amines, and other chemicals, adds
of material failures. Successfully and safely operating the to the species contributing to corrosion problems in the
petroleum refining industry is thus the challenge facing overhead system. Most of the corrosion and other damage
corrosion engineers in this industry. This chapter provides mechanisms affecting metallic materials in oil refining are
a brief overview of the topic of refining industry corrosion described in API RP 571 [5].
and, to a lesser extent, corrosion control and inspection. Crude unit overhead corrosion is widely described in
This topic is very extensive so readers are encouraged to the literature [6–8]. Amine-based products unintentionally
refer to other books related to the subject [1–4]. or intentionally added to the crude oil can also separate
Understanding the petroleum refining process is of from the crude oil during distillation and move upward in
paramount importance to material engineers, corrosion the tower. The amines, NH3, or both can combine with HCl
engineers, and inspection personnel involved in this industry. and form ammonium chloride salts (NH4Cl), amine hydro-
Descriptions of these processes are found elsewhere in this chloric salts, or both and become a source of fouling and
manual. In this chapter, the unified numbering system (UNS) severe corrosion for the upper trays or packing beds in the
is used to refer to corrosion resistant metals and alloys; distillation tower.
more generic names are used for most common materials. Some units have a preflash column where light naph-
tha and lighter components are removed from the feed and
17.2 Wet Corrosion either sent directly to the crude overhead system or pro-
The crude oil is fed to the crude distillation unit where cessed separately in downstream units. A preflash column
steam is injected into the distillation tower to aid fraction- overhead may operate at a temperature low enough that
ation. Steam is also used in ejectors to create vacuum in it can face similar corrosion problems as the atmospheric
vacuum distillation units, sometimes in the coils of furnaces tower overhead system. Because this corrosion depends on
as velocity steam to reduce residence time and internal coke water condensation, the overhead system temperature is
formation, and as stripping or heating medium in many a determining factor. The tower top temperature in some
parts of the oil refining processes. Thus, steam and water units is near or below the water dew point and hence water
are necessary parts of the refining petroleum process but, starts condensing within the top of the tower. Naphtha
at the same time, they represent a source of wet corrosion. is raw gasoline that does not condense within the atmo-
spheric column but goes overhead as vapors together with
17.2.1 Crude Unit Overhead Corrosion water vapor. Units with a two-stage overhead system are
The corrosion that is the subject of this section includes designed so that the first stage does not condense water
the top trays or packing, the overhead piping of the atmo- but only naphtha; the remaining naphtha and water con-
spheric distillation tower, the reflux line at the top of the dense in the second stage. The corrosion problems in these
distillation tower, the heat exchangers, and the condensers, systems occur in the second stage and are similar to those
pumps, and drums in the overhead system. Because of the in single-stage overhead systems. Thus, depending on the
high temperatures used in atmospheric and vacuum distillation unit design and operation, the tower top temperature may

1
Shell Projects and Technology, Shell Global Solutions (U.S.), Inc., Westhollow Technology Center, Houston, TX, USA
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437
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438 Petroleum Refining and Natural Gas Processing

vary and water condensation is expected to occur when the The corrosion of trays, packing, and demister made of alloy
temperature of the overhead vapor stream reaches the dew N04400 and trays made of super austenitic stainless steel
point that depends also on the pressure in the system and alloy N08367 have been attributed to amine hydrochloric
the water vapor content. However, condensation can also or NH4Cl salt corrosion. The environment developed under
occur upstream of the initial condensation point in cold these deposits is aggressive enough to completely dissolve
spots caused by loss of insulation on the tower and over- these alloys, particularly if the components are made of
head piping, cold weather, or even by cold reflux entering thin metal sheets. Alloy N06625, N10276, grade 2 titanium,
the column. This is referred to as shock condensation. or grade 12 titanium may offer better corrosion resistance
In spite of the several mitigation methods used for crude but when there are problems related to fouling and corro-
overhead corrosion control, the corrosion and fouling prob- sion with these salts inside the distillation tower, it is best
lems persist in many refineries. There have been problems to treat the source and thus prevent salt deposition from
with desalting [9], tower top temperature variation, spot occurring. Grade 2 is commercially pure unalloyed tita-
or shock condensation, and presence of tramp bases or nium; grade 12 titanium (Ti 0.8Ni-0.3Mo) is alloyed with
other uninvited contaminants. There have also been con- nickel and molybdenum. Alloy Ti-0.3Mo-0.8Ni (grade 12)
cerns about the presence of no extractable chlorides [10] has applications similar to those for unalloyed titanium
because of reported problems. These are usually non-water- (grade 2) but has better strength and corrosion resistance.
soluble organic chloride compounds that are not removed Changing the metallurgy of the internal components at the
by desalting. They only partially hydrolyze in the crude top of the tower should be the last resort.
heaters and the HCl thus produced joins the HCl normally
produced by inorganic chloride salts. The remaining non- 17.2.1.2 Vacuum Unit Overhead Corrosion
hydrolyzed portion of the organic chlorides is carried away Most of the subject of overhead corrosion and control is
with the naphtha and upper side streams. Attempts have devoted to atmospheric crude units, but vacuum distillation
been made to identify the impact of amine contaminants column overhead can also suffer similar corrosion problems
[11] and amine-based H2S scavengers [12] on the corrosion even though most vacuum units operate without added
in crude distillation units. All these factors may cause loss steam and are therefore drier. Even if there were steam
of pH control, loss of corrosion inhibition, increased initial in the vacuum distillation tower, it would not condense
condensate corrosion, increased fouling by hydrochloric because of the vacuum in the overhead system; this is until
neutralization salts and increased pitting or localized corro- the overhead stream reaches the condenser shells. Some
sion under deposit. When water separation is inefficient, salts do not hydrolyze in the atmospheric crude distillation
the naphtha reflux may carry some of the neutralized water furnaces but in the vacuum distillation furnaces. The result-
to the tower and once there, salts may deposit on trays ing hydrogen chloride vapor moves to the top of the vacuum
and packing as this water evaporates. If these salts form or distillation column and vacuum column overhead system.
fall on draw-off trays, they can also be taken with the side HCl corrosion can hence occur in the condenser shells, the
stream to downstream units. outside surface of the tubes in these condensers, and in the
receiver drum (the hot well). Because of the higher tem-
17.2.1.1 Corrosion-Resistant Materials for peratures normally used in the furnaces of vacuum units,
Crude Overhead Corrosion as compared with crude distillation unit furnaces, further
Carbon steel is still the most common metallurgy used for decomposition of sulfur species occurs that produces H2S
heat exchanger tubes in the crude distillation unit over- that travels to the vacuum tower overhead. Organic nitrogen
head systems. Some units have crude feed/overhead vapor compounds can also decompose and produce NH3. Some
exchangers to start heating the feed with the overhead refineries inject amine neutralizer and filmer inhibitor into
vapor stream. Most crude units have overhead condensers the overhead system of the vacuum distillation unit to con-
that could be of the shell/tube bundle type or fin fan air cool- trol corrosion. Oxygen can enter the vacuum system with
ers. In the case of cooling water condensers, this water is nor- air leaking connections and accelerate corrosion. Some cor-
mally oxygenated and the life of carbon steel bundles may rosive organic acids may form because of this oxygen and
be limited because the tubes suffer corrosion on the cooling contribute to the corrosion of carbon steel. In general, how-
waterside and the process side as well. Standard austenitic ever, vacuum overhead system corrosion is far less severe
stainless steels of the series 300 could resist the general cor- than corrosion in crude unit overhead systems.
rosion, but because of their susceptibility to chloride SCC
(Cl SCC), they are not normally used. Austenitic stainless 17.2.2 Wet H2S Corrosion and Cracking
steels of the series 300 are also susceptible to under-deposit There is a considerable amount of published literature
chloride-induced pitting on both the cooling waterside and on the subject of wet H2S cracking of steels [13]. The wet
process side. Duplex stainless steel S31803/S32205 and super H2S environment is defined as that having a total sulfide
duplex stainless steel S32750 can be used instead of 300 series concentration greater than 50 ppmw in the aqueous phase
stainless steels. Cu-Ni alloys C70600, C71500, and N04400 or even at least 1 ppmw if the pH is lower than 4.0. In the
have been used. Admiralty brass metals C44300, C44400, and gas phase, when handling only gases, the requirement is to
C44500 are used, but they are susceptible to NH3 stress cor- have more than 0.0003 MPa partial pressure of H2S [14]. It
rosion cracking (NH3 SCC). is not uncommon to have 50 ppmw or more total sulfide in
Alloy N04400 has traditionally been used as clad mate- the water collected in the overhead systems of both atmo-
rial, trays, packing, and other internal components in the spheric and vacuum distillation. The pH of this water is
crude distillation tower top. It is resistant to the HCl corro- usually higher than 4.0, but without neutralization the pH
sion prevailing in the crude distillation unit overhead for can certainly decrease to less than 4.0. Therefore, if these
most conditions but it has also failed by severe corrosion.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- definitions are applied, the carbon steel equipment in the
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Chapter 17 n Corrosion Inspection and Control in Refineries 439

overhead systems of both atmospheric and vacuum distilla- Susceptibility to wet H2S damage not only depends on
tion units would have to be considered in wet H2S service. the corrosive environment but also on the carbon steel type.
This means that pressure vessels in this service should Hydrogen-induced cracking (HIC) and hydrogen blisters (H2
comply with certain requirements when newly fabricated blisters) depend on cleanliness of the steel. Even if the steel is
[15–17] and the refinery should comply with certain inspec- not harder than 22 HRC, as hydrogen atoms diffuse through
tion practices for pressure vessels in service [18]. These the steel, they can be trapped in nonmetallic inclusions,
actions add cost to the construction of new equipment and combine with another hydrogen atom to form hydrogen
to the maintenance of existing equipment because of the gas within these defects, and build up enough H2 pressure
special inspection required for crack detection and other to create a HIC. If the HIC were well inside the wall thick-
wet H2S-related damage mechanisms. ness, the crack would not be apparent from the surface and
The required pressure and stress level to activate wet would be detectable only by ultrasonic inspection means. If
H2S SCC is not addressed in these recommended practices the HIC is close enough to the steel surface, the build-up of
and standards dealing with this topic. If the pressure is vac- H2 pressure at the defect can cause a bulge on the surface
uum or near atmospheric in the overhead systems, there is and thus it produces a H2 blister. HIC can occur isolated,
no driving force for cracks to propagate through thickness, randomly distributed, or aligned in a step-like form, in
except for the residual stresses. Residual stresses may be as which case it is referred to as step-wise cracking. In the
high as the yield strength of the steel but are confined to a presence of high-tensile stress, several HICs can form aligned
small area beyond which crack growth will arrest. The typi- in the through-wall direction, one form of which becomes
cal operating pressure at the overhead system of crude dis- SOHIC (stress-oriented hydrogen-induced cracking). The
tillation columns is 0.10–0.21 MPa so the required design most critical wet H2S damage is SCC followed by SOHIC,
for pressure vessels, piping, heat exchanger shells, and fin HIC, and H2 blisters.
fan cooler header boxes can be thin-wall construction. The HIC and H2 blistering can form a single and large crack
wall thickness is a determining factor for the hardness and extending parallel to the vessel wall or numerous and rather
the residual stress of carbon steel weldments. Welding thin small cracks. If there is concern with the integrity of the
wall vessels may neither result in hard heat-affected zone vessel due to widespread H2 blistering, HIC, or both, a window
(HAZ) nor in high residual stresses in common carbon is sometimes cut to remove the most affected area and an
steels used to fabricate refinery equipment using standard insert plate is welded in place. The usual recommendation
welding methods and procedures. However, shallow single is to post-weld heat treat (PWHT) after weld repair, but if
pass welds used as internal attachment welds or to fill pits H2 blisters or HIC are left in the steel that is not replaced
may result in hard HAZ and welds susceptible to wet H2S the H2 trapped will cause high-temperature hydrogen attack
SCC, and these should be avoided. These attachment welds at the temperatures and times typically used in PWHT
should be made using at least two passes and high heat [20]. There have also been instances where residual HIC
input for welding. Equipment with pitting damage should has developed into very large bulges during post-weld heat
be evaluated to determine whether they need to be repaired treatment as the steel softens and the hydrogen pressure
or left as they are. If repairs are required, proper repair proce- inside these existing HIC greatly increase with increasing
dures should be used. temperature during this heat treatment.
It is found that some refineries include their crude and The concern about wet H2S corrosion service is mainly
vacuum overhead system equipment in wet H2S service with pressure vessels. Most refineries do not specify post-
and some do not. A risk-based inspection approach [19] is weld heat treatment or inspection for wet H2S SCC for car-
recommended to deal with these inspection issues. A strat- bon steel piping made of seamless fully killed low strength
egy is often adopted to remove items from the special wet carbon steel (e.g., ASTM A-106, grades A and B). Seamless
H2S cracking inspection list when two or three separated pipe circuits have only circumferential welds to join pipe
inspections have already been performed, each after at least with pipe, and branch connection and attachment welds.
one unit run, and no indications are found. This would be Butt welds in these piping circuits are made with multipass
valid provided the operating conditions remain unchanged. welding where subsequent weld beads soften the weld pass
The wet H2S damage mechanisms are more relevant and associated heat affected zone underneath. It was once
in refinery process units that handle higher H2S concentra- stated that welding piping from outside only would leave a
tions than crude distillation. The high temperatures used compressive residual stress system that does not favor SCC.
in processes like visbreaking, fluidized catalytic cracking However, occurrence of stress cracking in alkaline media,
unit (FCCU), delayed coker, and other thermal cracking such as caustic and amine, has demonstrated that this is not
processes produce significant amount of H2S. In hydropro- true; there is a residual tensile stress system at the welds of
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cessing the desulfurization occurs by converting organic these piping circuits; otherwise caustic or amine SCC would
sulfur compounds into H2S that is then removed from the not occur. Thus, hardness is most likely the reason wet H2S
treated product. stress cracking does not occur in seamless low strength
The wet H2S phenomenon involves the corrosion reac- carbon steel type ASTM A-106 grades A and B. Also, the
tion of H2S with the steel and the generation of hydrogen, threshold level of the tensile stress required to cause SCC is
which, rather than combining with another hydrogen atom believed to be much lower for alkaline SCC than for wet H2S
and evolving as gas that moves away from the steel, it enters stress cracking. The presence of cyanides (HCN) is known
and diffuses into it. Just by being inside the steel, if this is to considerably increase hydrogen flux because they destroy
harder than about 22 HRC (Rockwell hardness, scale C), this the protective iron sulfide layer. Carbon steels exposed to
dissolved hydrogen can cause H2S SCC. The phenomenon is hydrofluoric acid (HF) may experience damage [21] in a
dependent on hydrogen flux, but it will not occur if the steel very similar manner as in wet H2S environment. The HF
is not hard enough, the stress is not high enough, or both. environment is present in the HF alkylation process.
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440 Petroleum Refining and Natural Gas Processing

17.2.3 Ammonium Bisulfide Corrosion duplex stainless steel S31803/S32205. Alloy N10276 was
H2S and NH3 react to form ammonium bisulfide (NH4HS). the most corrosion resistant of all the alloys tested.
The concentration of NH4HS is not very high in visbreaker, In the field, there are additional factors that may play
FCC, delayed coker, and fluidized coker units, which is why important roles on the NH4HS corrosion. The wash water
carbon steel is still suitable for most equipment and piping is usually injected into a 100 % vapor stream and, as this
used in the recovery units where light end products from stream cools down, hydrocarbon starts condensing either
these units are fractionated. in a fin fan cooler bank or cooling water exchangers. Part
NH4HS corrosion is a well-known concern in hydro- of the injected wash water may vaporize to condense back
processing units. The reactor effluent stream is cooled from into water when it cools down. Thus the water quality and
about 120 °C–200 °C to 37 °C–66 °C using fin fan coolers. source, wash water rate, the location of the injection point,
This system has been known as the reactor effluent air whether it is multiple or single, if it has quill or a spray nozzle,
cooler (REAC), although shell/tube bundle cooling water will all matter. Among all these factors, the flow regime
exchangers are also used. The main problem is fouling due to plays a major role [25]. Best practices for water washing in
the presence of NH4HS [22]. To avoid NH4HS salt deposition hydroprocessing units have been described [26] to address
water wash is necessary to dissolve and wash away this salt, some of these topics.
but in doing so water is introduced that becomes corrosive In the inlet or outlet piping of the REAC system,
itself. Thus, the corrosion is associated with salt deposition NH4HS corrosion is expected to be more pronounced at the
and concentrated NH4HS solution. High fluid velocities extrados of elbows, the impingement side of the tee and, in
have the effect of removing the protective iron sulfide layer general, where there is high turbulence or a change in the
that forms on the metal surface and thus greatly accelerate direction of flow in single liquid phase flow condition.
the corrosion.
Oxygen introduced by the water injected into the hydro- 17.2.4 Ammonium Chloride Corrosion
carbon stream can accelerate corrosion. Chloride present in When present, chlorides from HCl in hydroprocessing reac-
the feed or introduced by the use of catalytic reformer hydro- tors can combine with NH3 and produce NH4Cl. Several
gen does not seem to make NH4HS corrosion any worse but cases of NH4Cl corrosion have been reported in the REAC
NH4Cl salt can start precipitating at a temperature higher system [27], the fractionator feed preheat exchangers [28],
than that for NH4HSI. NH4Cl salts formed upstream of the and also in the stripper column overhead [29]. NH4Cl cor-
wash-water injection point can cause fouling and severe rosion could be very aggressive to carbon steel and other
under deposit corrosion if these salts absorb moisture. alloys. Its presence can also encourage chloride SCC (Cl
The problems with REAC corrosion have persisted [23] SCC) [30] in austenitic stainless steels. The catalyst in cata-
in otherwise noncorrosive conditions for unfavorable fluid lytic reformer units is activated with addition of chloride
distribution to the condenser system. The cause of corrosion compounds that may become the source of HCl that is
is reasonably well understood, but it is recognized that is a carried with the H2 that is used in hydroprocessing. Nickel
complex phenomenon that depends on a larger number of base alloys N06625 or N08825 may be required to resist this
variables, other than just the presence of H2S/NH3, NH4HS aggressive corrosive environment. However, as mentioned
concentration, and velocity. There is usually a bank of air earlier, the remedy actions should first attempt to eliminate
coolers, several cooling water shell/bundle exchangers, or the source of chloride whenever possible, rather than to go
both in the REAC. The design of the incoming piping to directly for upgrading the metallurgy. Catalytic reformer H2
these condensers is a significant variable, a balanced design is often passed through chloride traps, absorbers, or pres-
being preferred because of equal distribution of hydrocar- sure swing adsorption to remove the HCl before using it in
bon and wash water and minimum differences in velocity hydroprocessing plants.
among the several condensers.
Recent research results were published [24] that 17.2.5 Acid Corrosion
depart from rules of thumb previously applied to these There are other process units in the oil refining industry that
systems. The statement that corrosion is low at NH4HS are corrosive because of the process itself. For instance, the
concentration of 2 wt % or less still seems valid, with catalyst in alkylation is pure HF [31] or sulfuric acid [32],
the added information that the effect of velocity at this both very corrosive to metals and alloys. The materials used
concentration is only marginal. At intermediate NH4HS in HF and sulfuric acid service have been fully described
concentration of 2 to 8 wt %, low to moderate corrosion elsewhere [33,34]. Polymerization unit is a different process
was observed, significantly increasing with velocity. At in that solid phosphoric acid catalyst is used. Because this
intermediate NH4HS concentration greater than 8 wt %, catalyst is fragile, fine catalyst particles may break and be
moderate to high corrosion was observed, significantly carried away downstream. At the normal reactor temperature
increasing with velocity. The H2S partial pressure was and pressure, there is no concern of corrosion, but these
found to be a major factor that was deemed necessary fine particles may be carried away downstream of the reac-
to consider when predicting corrosion rate. The velocity tors, where they may react with water or moisture and form
limit of 6.1 m/s was found to be too conservative at low phosphoric acid that may corrode both piping and vessel
NH4HS concentration and low H2S partial pressure and too walls where the wet material deposits on the surface.
liberal at high NH4HS concentration and high H2S partial
pressure. The presence of hydrocarbon mixed with the 17.2.6 Dead Legs and Injection Points
sour water resulted in significant reduction of corrosion, The corrosion rate in dead legs can vary significantly from
as compared with sour water without it. Super duplex adjacent active piping and hence, they represent places
stainless steel S32750 and super austenitic stainless steel demanding special attention. Dead legs include points
N08367 exhibited far more corrosion resistance than both at the stagnant end and the end at the connection to
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AST-MNL58-11-0801-017.indd 440 3/12/13 2:45 PM

Chapter 17 n Corrosion Inspection and Control in Refineries 441

an active line. Several corrosion mechanisms associated formation cannot be avoided because these steels, under
with injection points have become apparent to refineries high-temperature sulfidic corrosion conditions, will natu-
over the years. Many of these problems have resulted in rally form it; moisture and air are naturally present in the
highly localized deterioration and even piping failures. The environment as soon as the equipment or piping is opened
approach has been to also treat them as separate inspec- to the atmosphere for maintenance or inspection. The
tion circuits that demand special attention and thorough required material condition is being sensitized. Because the
inspection on a regular basis. Both topics, dead legs and sulfide scale forms on the inside surface, PTA SCC starts on
injection points, have been covered in piping inspection the inside surface and propagates through wall thickness
code [35], and inspection practices for piping system toward the outside surface.
components [36]. There is a technical committee report by Soda ash neutralization procedure is used to prevent
NACE International on the subject of refinery injection and PTA SCC. Decoking furnace tubes is often done by mechan-
process mixing points [37]. The use of quills or injectors ical means, using coke cutting “pigs” pushed with water,
is always advisable. There are many design considerations which should also contain similar amount of soda ash for
and aspects that need to be taken into account to achieve neutralization purpose. The aqueous soda ash solution is
trouble-free injection points. also recommended for hydrotesting austenitic stainless
steel heater coils, pressure vessels and piping in this service
17.2.7 Sensitization likely to produce PTAs. After using this alkaline water, it is
Solution annealing is a heat treatment used in 300 series of paramount importance that all the remaining solution is
stainless steels and it consists of heating the material up drained, particularly the low points in the system that can
to a temperature above 1066 °C and holding it long enough concentrate carbonate and chlorides that can cause either
for the carbon to go into solution. After this, the material chloride SCC or caustic type SCC upon heating.
is quickly cooled to prevent the carbon from coming out Applying all these measures to prevent PTA SCC is time
of solution. Solution annealed material is in its most consuming and costly. Thus, determining when they are
corrosion-resistant and ductile condition. Sensitization in really required or not can be gainful. There is an increasing
the steel occurs from chromium depletion along austenite amount of austenitic stainless steel being used to deal with
grain boundaries due to chromium carbide precipitation high-temperature sulfidic corrosion, naphthenic acid corro-
during welding these types of austenitic stainless steels or sion, or both in crude and vacuum distillation units. The
during high-temperature operations, higher than 370 °C. furnaces heat the feed to about 370 °C in atmospheric
In certain corrosive environments, sensitized austenitic distillation and up to 400 °C in vacuum distillation. This
stainless steels may suffer intergranular corrosion or even sets the temperature the metals will be exposed to outside
intergranular SCC. Because of this, low carbon grade or the furnaces. Thus, in the case of crude units, the tempera-
stabilized grade S32100 and S34700 are used. Stabilizing heat ture may be below the range required for sensitization.
treatment performed after the material has been solution However, furnace tubes can be exposed to at least a 50 °C to
annealed enhances the sensitization resistance of these stabi- 100 °C higher temperature than the fluid inside the tubes;
lized grades. The stabilizing heat treatment is to tie up the thus, they are expected to be more susceptible to sensitization
carbon with the stabilizing elements (either Ti or Nb) and and, hence, to PTA SCC. Only a few instances of PTA SCC
thus leave no carbon available for sensitization. Sensitization have actually been reported to occur in crude and vacuum
is more likely in the presence of coke at temperatures high distillation units.
enough for carburization to occur; this would provide more PTA SCC occurs when there is not operating pres-
carbon to the steel for the sensitization phenomenon. sure. The stress causing it is the residual stress present in
weldments or that arising from lack of flexibility in piping
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17.3 SCC circuits and piping-to-equipment connections. If it occurs

There are a number of SCC mechanisms that may affect and propagates through thickness, the cracking is detected
the materials in oil refining equipment and piping. The during the start-up procedure or soon after the unit returns
SCC mechanism caused by wet H2S and HF corrosion was to service, requiring a new shutdown for inspection, repair,
already described. This mechanism is basically delayed and replacement. Thus, it can be a costly event, not only
cracking due to hydrogen embrittlement. In the more because of the maintenance cost involved in the repair job
general cases of SCC, the cracks form and grow by anodic but also due to the loss of production.
dissolution, which is the typical mechanism that does not The reported sensitization temperature ranges for
depend on the material hardness or strength level, although stabilized grade S32100 and S34700 steels is 400 °C–815 °C.
cold working usually has an adverse effect. The cracking Operating temperature for hydroprocessing units may vary
process in this case involves the direct action of corrosion from 300 °C to 450 °C. Thus, in some low-severity hydro-
on the cracking formation and growth mechanism. In all processing units, the piping and feed/effluent exchanger
cases of SCC, three contributing factors are required, the temperature would be below the sensitization range but,
presence of tensile stress, the wet corrosive medium, and as mentioned earlier, furnace tubes can experience higher
the susceptible material or metallurgical condition. temperature and are hence more likely to sensitize in
service.
17.3.1 Polythionic Acid SCC (PTA SCC) The most established corrosive environment leading
PTA SCC refers to a branched intergranular SCC that can to high PTA SCC potential is that containing hydrogen
occur in sensitized austenitic stainless steels. PTA refers with significant amount of H2S. Some hydroprocessing
to the family of acids that can form by the oxidation and units use sweet hydrogen (with no H2S), so this corrosive
hydrolysis of iron sulfide films that formed on the austenitic environment would not form but at the reactor where the
stainless steel surface during service. This sulfide film conversion of organic sulfurs species to H2S occurs and is
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442 Petroleum Refining and Natural Gas Processing

carried downstream. Some other hydroprocessing units use chlorides has a synergistic effect even causing chloride SCC
sour recycle hydrogen (with H2S) so this H2/H2S corrosive in the absence of oxygen. The presence of molybdenum, as
environment would be present at the hydrogen injection an alloying element, tends to inhibit chloride SCC. Low pH
point and downstream. aggravates chloride SCC at least until cracking is initiated;
Hydroprocessing reactors usually have their internal thereafter, the pH conditions within cracks become acidic
surfaces protected by a layer of austenitic stainless steel and do not necessarily coincide with those of the bulk
to provide for the necessary corrosion resistance to high- environment. Although it has not been possible to find a
temperature sulfidic corrosion in the presence of a H2/H2S safe low-chloride concentration, it has been customary to
environment. The protective layer of austenitic stainless specify a maximum of about 50 ppmw chlorides for water
steel may be a weld overlaid layer or clad. The clad mate- that is used for hydrotesting, washing, or flushing austenitic
rial is applied to the base metal by hot rolling or explosion. stainless steel equipment and piping. Kerosene or naphtha
Hot-rolled clad forms a metallurgical bonding with the base has been used instead of water to perform hydrotesting in
metal, while the explosion bonding is a solid-state welding heater tubes.
process that uses the forces of controlled detonations to Because of the concern of chloride SCC, corrosion and
accelerate one metal plate onto another and thus create material engineers are sometimes forced to select alloys
a diffusionless bonding. Because of the problem with other than austenitic stainless steels for equipment and
hydrogen-induced clad disbonding during service, weld piping in the oil refining industry. Duplex stainless steels
overlay is preferred, with the added beneficial effect have become popular [40] in this respect, but these steels
that low carbon and chemically stabilized weld overlays have temperature limitations. It is not recommended to
appear very resistant to PTA SCC if the operating tempera- use duplex stainless steels beyond about 280 °C–340 °C.
ture is below 455 °C. Prolonged exposure to temperatures exceeding these limits
The PTA SCC concern should be limited to austenitic may cause undesirable metallurgical changes in duplex
stainless steel exposed to high-temperature sulfidic corro- stainless steels. Nickel-based alloy N08800 and N088250
sion with and without H2. Extending the practices to prevent are resistant to chloride SCC. In general, nickel-base alloys
PTA SCC in austenitic stainless steels exposed only to H2S are often used under wet operating conditions because of
or NH4HS wet service may be overly conservative. their resistance to chloride SCC.

17.3.2 Chloride SCC 17.3.3 Caustic SCC

Chloride SCC refers to a branched cracking that can occur Caustic sodium hydroxide (NaOH) is used in many petro-
in austenitic stainless steels independently of whether they leum refinery applications in a wide range of concentrations
are sensitized or not. Usually in nonsensitized austenitic and temperatures. Caustic SCC of carbon steel equip-
stainless steels the cracking is transgranular, but if the steel ment and piping has been a well-known phenomenon. It
is sensitized it can also occur intergranularly. The chloride is an intergranular SCC mechanism producing multiple
SCC has been a potential damage mechanism for austenitic branched cracking. The caustic soda service chart [41] is
stainless steels used in oil refineries. The potential for still used today to determine the temperature and concen-
external chloride SCC under thermal insulation has been tration, beyond which carbon steel may become susceptible
recognized and recommended practices have been issued to caustic SCC. Post-weld heat treatment is effectively used

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
[38] to address this potential problem. The problem occurs to mitigate the problem because it significantly reduces the
when water and chloride enter the insulation material. The residual stress. However, above certain temperature level
chlorides can be from the insulation material itself or exter- and given caustic concentration, even low stresses may still
nal sources, more frequently coastal atmospheres, nearby result in cracking, in which case not even post-weld heat-
chloride-containing chemical processes, wash water, fire treated carbon steel is suitable for hot caustic service.
protection deluge systems, and process spillage. The hot Austenitic stainless steels [42] and even nickel-based
metal surface concentrates the chlorides by evaporation. alloys may become susceptible to caustic SCC at relatively
Equipment that cycles through the water dew point is high temperatures. With austenitic stainless steels, the
particularly susceptible because of chloride concentration. morphology of cracking is often transgranular and indistin-
Most external chloride SCC failures occur when the guishable from chloride SCC but intergranular cracking is
metal temperature is in the hot water range, 50 °C to also observed. Because chloride is a common contaminant
150 °C, and less frequently when the temperature is out- in caustic, SCC failures in caustic environment may not be
side this range. Water is usually necessary and it is gener- conclusively ascribed to either chloride or caustic. Also,
ally believed that it will not occur at temperatures where although caustic is the most common SCC encountered,
water cannot exist in liquid form. An apparent temperature other alkali metal compounds may cause similar SCC
threshold of about 50 °C–60 °C has been observed, below problems. For instance, carbonate SCC has occurred in low
which cracking probability becomes very low. Sufficient points that have not been properly drained after alkaline
tensile stress must be present for chloride SCC to occur. washing done with soda ash to protect austenitic stainless
Protective coating systems have been recommended for steel piping systems in hydroprocessing units from PTA
austenitic stainless steels under insulation. SCC. These pockets of alkaline water tend to dry out and
Chloride SCC can also occur due to presence of chlorides thus significantly increase the alkaline concentration; SCC
in the process environment inside equipment and piping. may then occur in hours when warming up the unit for
Oxygen is usually necessary, but this may vary with the start up. Because of this potential problem, some refiner-
nature of the aqueous solution. For instance, dilute aque- ies have selected nickel-based alloy N08800 or N088250
ous solutions do not cause chloride SCC if completely free for small-bore connections at low points in these austenitic
of oxygen [39]. The simultaneous presence of H2S and stainless steel piping systems to reduce the SCC problem.
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Chapter 17 n Corrosion Inspection and Control in Refineries 443

Duplex stainless steels and alloy N04400 may also outside the scope of this chapter; a description was given
experience SCC under certain conditions of concentra- for most common ones.
tions and temperatures. Alloy N06600 is preferred to alloys
N08800 and N088250, which may crack by caustic SCC 17.4 Dry Corrosion
more easily than alloy N06600. The technically correct Like high-temperature oxidation of metals, dry corrosion
metal for the greatest immunity to caustic SCC is nickel, occurs in the absence of water. It is attributed to sulfur,
either N02200 or N02201 sometimes used as clad material. naphthenic acids, or both. Once the temperature of the
crude oil feed reaches or exceeds about 230 °C, problems
17.3.4 Alkaline SCC with high-temperature sulfidic corrosion and naphthenic
There are other common substances that can cause inter- acid corrosion may begin. Both corrosion mechanisms are
granular SCC in carbon steels, usually with multiple temperature/velocity dependent; therefore, the most critical
fine-branched cracks. A list of the most common alkaline parts are the places and locations where the temperature
environmental cracking mechanisms affecting carbon steels and the velocity or turbulence is the highest. These locations
in oil refining services is given in the literature [15]. These are typically furnace tubes, furnace outlet piping, transfer
are caustic; alkanolamine-containing CO2, H2S, or both; and line (from the furnace to the distillation tower), pumps,
alkaline sour waters containing carbonates. Alkanolamine and downstream control or pressure let down valves. The
solutions are widely used in oil refineries and gas plants to internal components and wall of the distillation towers can
remove H2S, CO2, or both from hydrocarbon streams in the also be affected.
liquid or vapor phase, in plants referred to as amine units. Depending on the amounts and aggressiveness of the
Amine SCC is dealt with in the API RP 945 [43]. There is a sulfur species and naphthenic acids present, the potential
dependence of the amine SCC and the metal temperature for corrosion could continue to occur in the side stream
above which cracking is most likely. Thus, post-weld heat piping circuits and bottom lines of distillation towers, includ-
treatment is recommended for carbon steels in amine units ing the associated heat exchangers, drums, and pumps. The
depending on the type of amine used and the operating tem- atmospheric bottoms are fed to the vacuum unit where
perature. The temperature limit varies from 60 °C to 88 °C. the potential for high-temperature sulfidic corrosion and
There is no temperature limit for monoethanolamine. naphthenic acid corrosion continues. Actually, naphthenic
Not only the normal operating temperatures should be acid corrosion is typically more critical in vacuum distil-
considered, but also the effects of heat tracing and steam- lation units than in crude distillation units. The vacuum
out on the metal temperature of carbon steels in contact tower bottoms are fed to visbreaker, delayed coker, or fluid-
with the amine or caustic solution. Equipment and piping ized coker units, but the corrosion concern in these units
have been known to crack during steam-out due to the pres- is more high-temperature sulfidic corrosion rather than
ence of amine. The same concern arises when performing naphthenic acid corrosion. For side streams, the potential
any kind of hot work on existing carbon steel equipment and for these two corrosion mechanisms continues in all the
piping in amine units. These should be thoroughly cleaned downstream units for as long as the operating temperature
before attempting steam-out or before conducting repairs reaches or exceeds about 230 °C.
or alterations involving welding. Washing and flushing
the equipment and piping with copious amounts of water 17.4.1 High-Temperature Sulfidic Corrosion in
to remove any residual amine or caustic contamination the Absence of Hydrogen
achieve this. As a conservative precautionary measure, The modified McConomy curves have been generally use-
refineries may apply post-weld heat treatment to every ful for predicting corrosion rates for various steel alloys
carbon steel equipment and piping in amine and caustic in refining process streams based on total sulfur present
units, irrespective of the operating temperature. This is [49,50]. The original McConomy curves were published in
usually the case for carbon steel piping and equipment 1963 by the API Subcommittee on Corrosion [51]. They
handling lean amine. were hand-fitted curves through widely scattered points
Intergranular SCC in carbon steels has been reported obtained by industrial surveys containing field and labora-
in the FCC main fractionator overhead systems [44] and tory corrosion rates. The predicted corrosion rates were
attributed to carbonate SCC. It has been recently noticed that those on the curves, and these were found to be overly con-
as the FCC feed is hydrotreated to reduce its sulfur content, servative and were later modified. A corrosion rate multi-
new conditions are created that favor carbonate SCC [45]. plier factor was then provided to account for sulfur content
The Task Group 347 of NACE International recently issued from 0.05 to 5 wt %. The curves show increasing corrosion
a technical committee report on this subject [46]. When rate in a logarithmic scale from practically 0 mm/year to
metallographic cross-sections of damaged carbon steels are about 2.54 mm/year, at increasing temperature on a lineal
examined, the damage consists of intergranular oxide-filled scale, from about 260 °C to 400 °C. There are seven roughly
branched cracks, indistinguishable from caustic and amine parallel curves from top to bottom corresponding to car-
SCC. Similar type of damage has been found in buried bon steels, 1–3 wt % Cr steel, 4–6 wt % Cr steel, 7 wt %
pipelines in certain soil environment [47]. Post-weld heat Cr steel, 9 wt % Cr steel, 12 wt % Cr steel (S40500, S41000,
treatment is normally applied to prevent carbonate SCC in S41008), and 18Cr/8Ni austenitic stainless steel.
oil refineries. Crude oils having less than about 0.6 to 1.0 wt % sulfur
Alkaline SCC also can occur in carbon and low-alloy are usually referred to as sweet and those having higher
steels in anhydrous ammonia service [48]. The list of all sulfur content are known as sour. The definition is arbitrary
possible cracking mechanisms that could affect metals and but has been the basis for making material selection. When
alloys commonly used in the oil refining industry has not high-temperature sulfidic corrosion becomes significant,
been exhausted here, but the description of each of them is upgrading the metallurgy from carbon steel to 5Cr–½Mo
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444 Petroleum Refining and Natural Gas Processing

steel is preferred, rather than to 1¼Cr–1½Mo and 2¼Cr–1Mo the fractionation and distillation facilities downstream of
steels that would not offer significant corrosion resistance hydrotreaters and hydrocrackers. They reported that some
over carbon steel. Higher alloyed steels 7Cr–½Mo and hydroprocessing units experienced aggressive corrosion
9Cr–1Mo do offer further resistance to sulfidic corrosion rates, while many did not. In some cases, hydrocarbon
and are also used. Ferritic stainless steel type S40500 or streams with low sulfur content, in the order of ppm
martensitic stainless steel type S41000 or S41008 is even (weight), caused significant corrosion.
better but these steels are not often used as solid plates to On the other end, there are well-known cases of corrosion
fabricate pressure vessels or piping because of difficulties of being lower than those predicted by the modified McCo-
welding. These 12 wt % Cr steels are widely used for distil- nomy curves in distillation units processing heavy and
lation trays, packing material, and clad though. All of the extra heavy crude oils. Some of these units are processing
austenitic stainless steels of the series 300 have excellent sourer crude oils than those for which they were originally
resistance to high-temperature sulfidic corrosion. designed and have shown corrosion rates lower than those
Crude distillation units designed for processing sweet predicted by the modified McConomy curves. Clearly, this
crude oils are basically constructed with carbon steel, with indicates that oil refineries cannot rely on these curves
limited use of 5Cr–½Mo steel, usually located in the tubes alone and that the reliability of the plant still depends much
in the furnace, and stainless steel type 12 wt % Cr steel for on inspection, with particular attention being paid to steels
trays and other internal components in the atmospheric that are supposed to be experiencing higher corrosion rate.
and vacuum distillation towers, as well as side stream strip-
pers. As the potential of high-temperature sulfidic corrosion 17.4.2 H2S/ H2 High-Temperature Sulfidic
increases, so does the use of 5Cr–½Mo, 9Cr–1Mo, and Corrosion
S40500, S41000, or S41008. Thus, crude units designed to Hydroprocessing units require the use of hydrogen that,
process sour crude oils are recognized because they contain together with H2S, creates special high-temperature sulfidic
appreciable amounts of these alloyed steels. The tubes in corrosion environments that are much more aggressive
the furnaces are of particular concern because the metal than sulfidation in the absence of hydrogen. The corrosion
temperature is higher than in piping and equipment. The rate predictions are made using the Couper-Gorman curves
furnace outlet piping, transfer line piping, and flash zone [54] where the correlation was established with the pres-
where the feed enters the distillation columns can also be a ence of H2, temperature, and mole % of H2S, starting with
concern because of high velocities, particularly in vacuum less than 0.002 (20 ppm by volume) to higher than 1.0 %.
unit transfer lines where velocities may be 60–140 m/s or There are two categories for the prediction of the corro-
higher. sion rate, naphtha, used for naphtha and light distillates
Many refineries were originally designed and constructed such as kerosene and diesel, and gas oil, used for all other
to process sweet crude oils. As sweet crude oils become scarce hydrocarbons and H2 without hydrocarbon present. The
and more expensive, the trend has been to process sourer and latter refers to the handling of hot recycle hydrogen that
more acidic crude oils. Thus, it is not uncommon to find can contain significant amount of H2S with only traces of
refineries that have and are processing these sourer crude hydrocarbons.
oils in units that still have carbon and 5Cr–½Mo steels in Carbon steel is the most susceptible steel to H2S/H2 high-
places where the modified McConomy curves would predict temperature sulfidic corrosion; increasing chromium content
higher corrosion rates than they are actually experiencing. to 5 wt % or less provides only a marginal improvement.
This is not to say that the modified McConomy curves are not Corrosion resistance is modest with increasing chromium
correctly predicting the corrosion because in cases of pip- content up to 9 wt %; a minimum of 12 wt % Cr steel is
ing failures or early detection of corrosion during on-stream required to see a more significant increase in corrosion
inspection programs, it is often found that the measured resistance. In general, most units processing gas oils or
corrosion rates coincide reasonably well with those predicted heavier hydrocarbon streams make use of austenitic stain-
by the modified McConomy curves. In this sense, they could less steels in the feed/effluent heat exchangers, the piping in
be considered upper bound predictions. and out of the furnace, the furnace tubes, the reactor, and
Although it is still the practice to specify the total sulfur the reactor effluent piping back to the feed/effluent heat
content, it is now known that certain organic sulfur com- exchangers. Some units processing naphtha or even diesel
pounds, referred to as reactive sulfur, are mostly responsible do not extensively use austenitic stainless steels but Cr-Mo

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for high-temperature sulfidic corrosion. These are the organic or even carbon steels. As in the case of sulfidic corrosion
sulfides, disulfides, polysulfides, and mercaptans. Noncorro- without H2, actual corrosion rates measured in the field
sive sulfur compounds are the nonreactive compounds, and are sometimes lower than predicted by the Couper-Gorman
they are mainly the various thiophenes. Although it seems curves. Thus, these could also be considered upper bound
obvious that the correlation between sulfidic corrosion and predictions. Austenitic stainless steels have performed well
corrosion rate should be based on the amount of reactive and usually experience negligible corrosion rates in this
sulfur content, most laboratories are equipped only to deter- service.
mine the total sulfur content and thus this is still widely used
today. 17.4.3 Naphthenic Acid Corrosion
Higher corrosion rates than those predicted by the mod- Even though naphthenic acid corrosion has been recog-
ified McConomy curves have also been reported in cases nized for many years [55], it is still the subject of research
where significant concentrations of mercaptans are present and publications [56,57]. The rule of thumb has tradition-
[52]. An industrial survey [53] recently showed that corro- ally been to consider a neutralization number (or total acid
sion rates could be higher than predicted by these curves in number [TAN]) of 0.5 mg KOH/g as the threshold beyond
the hydrogen-free portion of desulfurizing units, specifically which naphthenic acid corrosion may begin occurring and
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Chapter 17 n Corrosion Inspection and Control in Refineries 445

therefore when it is required to use more corrosion-resistant the safe zone of no attack; the zone of high-temperature
steels. hydrogen attack is on and above the curve. There used to be
As the severity of naphthenic acid corrosion increases, a C–½Mo steel curve located between the carbon steel and
the problem starts occurring in the vacuum furnace tubes, 1Cr–1½Mo curve but this was deleted because of reported
the vacuum furnace outlet piping, the vacuum transfer cases of hydrogen attack in C–½Mo steel under this curve.
line, as well as the piping circuits handling heavy vacuum Currently, the applicable curve for C–½Mo steel is the carbon
gas oil (HVGO) and the overflash in the vacuum tower. At steel curve.
this stage, problems with naphthenic acid corrosion may The API has issued a document that describes the
also start appearing in the atmospheric distillation unit. technical basis for this recommended practice. The validity
The places most likely to suffer naphthenic acid corrosion of the Nelson curves as currently published in API RP 941
are again the furnace tubes, furnace outlet piping, transfer is confirmed in this document and the presence of stainless
line, and the flash zone where the feed enters the distillation steel clad material, even for ferritic stainless steel clad,
column. There are usually fewer problems with naphthenic is given a credit, while currently this is not the case. In
acid corrosion in the diesel and kerosene sections of the general, hydroprocessing units use either Cr-Mo steel or
crude units, although there have been recent reports claim- austenitic stainless steels in all the hot areas of the process
ing naphthenic acid corrosion in the kerosene section [58]. because of the H2S/H2 sulfidic corrosion potential. Because
Likewise, there are usually fewer problems with naphthenic of this, there is no concern of hydrogen attack; all these
acid corrosion in the LVGO section of vacuum distillation steels offered sufficient resistance to it, except for old reac-
units. In most cases, the bottom stream from the crude tors and feed/effluent exchangers that were built in C−½Mo
and vacuum distillation towers appeared less corrosive steel. The most common areas of hydrogen attack concern
than the crude itself and the gas oil streams. In the case are those that were originally fabricated in carbon steel or
of atmospheric bottoms, naphthenic acid corrosion typi- C−½Mo steel and that are close or slightly exceed the limit
cally becomes a problem only at the vacuum furnace and condition for hydrogen attack, because of the downgrading
downstream. of C−½Mo steel or operational changes made in the units
Naphthenic acid content in naphtha, kerosene, and die- or the process after they were designed and commissioned.
sel streams going to hydrotreater units has not yet been of Even though there have been no reported instances
concern with regard to naphthenic acid corrosion. Gas oils of high-temperature hydrogen attack in Mn–½Mo steels,
may have the potential to cause naphthenic acid corrosion the API RP 941 makes no distinction between this and the
in these units, but it has been a concern only upstream of conventional C−½Mo steel. Experiments led by the author
the injection point of hydrogen and where the temperature with one-side accelerated test suggested that Mn–½Mo was
is higher than about 230 °C–250 °C. Experience has shown superior to C−½Mo steel. Manganese is a noncarbide-form-
that naphthenic acid corrosion does not occur or it is neg- ing element, and the argument has been that not enough
ligible downstream of the hydrogen injection point [59]. information has been gathered to support this claim. This is
It does not occur downstream of heaters in delayed coker an area that certainly requires confirmation because there
units either, but in this case it is because the naphthenic are still some old Mn−½ Mo steel reactors in hydropro-
acids decompose at the outlet temperatures of about 500 °C. cessing units that have been treated just as C−½Mo steel.
Recognizing that there is a complex interaction between The results of these one-side accelerated tests conducted
two competing corrosion mechanisms, the corrosion rate with both C−½Mo and Mn−½Mo steel in the normalized
determination tables found in API Publication 581 contem- and annealed condition using 1 °C/min cooling rate are
plate both sulfidation and naphthenic acid corrosion but shown in Figure 17.1. The best hydrogen attack resistance
are still based on total sulfur (wt %) and TAN. In any case, was observed in the normalized heat treatment condition.
the tables tend to reflect the observed phenomenon that low C−½Mo steel in the annealed condition exhibited the same
sulfur produces higher naphthenic acid corrosion and that resistance to hydrogen attack as carbon steel. Similar trend
sulfur inhibits naphthenic acid corrosion and thus reduces was obtained for Mn−½Mo steel, but in this case the resis-
the corrosion rate with increasing sulfur. The fact is that tance of Mn−½Mo in the annealed condition (its worst heat
simple ways of accurately predicting corrosiveness have not treatment condition) was superior to C−½Mo steel in the
yet been found. normalized condition (its best heat treatment condition). Tests
were also conducted to assess the effect that the cladding has
17.5 Other Damage Mechanisms on increasing the hydrogen attack resistance. Calculation
17.5.1 High-Temperature Hydrogen Attack was made so that the hydrogen partial pressure at the
The use of hydrogen at high temperature and pressure clad-base metal interface was the same as the hydrogen
creates conditions for high-temperature hydrogen attack. pressure used in the test for the sample without clad and
Thus, this material degradation mechanism applies to yet, hydrogen attack proceeded 7.5 times faster without
hydrogen reformer, catalytic reformer, and hydroprocessing clad. This finding confirmed a protection effect of having
units. Recommended practices for the selection of materials an austenitic stainless steel layer on the C−½Mo steel. Tests
in high-temperature hydrogen attack service is described in were not conducted with ferritic or martensitic stainless
detail in API RP 941 [60]. Material selection is based on the steel clad.
so-called Nelson curves. These are curves with a temperature Existing C−½Mo steel equipment operating above the
scale on the vertical axis versus partial pressure of hydrogen carbon steel Nelson curve is subject to regular and costly
on a horizontal axis. There are empirical curves for carbon inspection for hydrogen attack. This kind of inspection poses
steel, 1Cr–1½Mo, 1¼Cr–½Mo, 2¼Cr–1Mo, 2¼Cr–1Mo–V, problems in that the clad or weld overlay does not allow
3Cr–1Mo, and 6Cr–½Mo steels. Conditions of temperature
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access to the internal surface and the damage in the form
and hydrogen partial pressure below the curve delineate of intergranular fissuring is not detectable by conventional
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446 Petroleum Refining and Natural Gas Processing

6 basis of sulfidic corrosion, naphthenic acid corrosion, or

both. In cases where these corrosion mechanisms do not
apply, it is common to use carbon steel, 1¼Cr–½Mo, or
5 2¼Cr–1Mo steels, depending on the design pressure and
Annealed expected maximum metal temperature. API Standard 530
HTHA Penetration, mm

[61] provides the method most commonly used to calcu-

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4
late heater-tube thickness in petroleum refineries. Both
API Standard 530 and RP 579 [62] provide methods for
C-0.5Mo Steel assessing the remaining life of heater tubes. The predic-
3
Normalized
tions of remaining life are as good as the historical data
on which they are based; oversimplifying the assumed
2 conditions may lead to under- or overestimations [63]
that render the approach useless.
Mn-0.5Mo Steel
Annealed
Heater tubes in petroleum refineries are also designed
1 Carbon with enough safety margins for prolonged service, and most
Steel
Normalized
tube failures in refineries can be attributed to overheating
by flame impingement, coke build-up inside the tubes,
0
0 20 40 60 80 100 irregular flow, and operational upsets. Excessive overheat-
Exposure Time in hours ing of the heater tubes under internal pressure may consume
a large proportion of the available remaining creep life, and
Figure 17.1—Accelerated short-time hydrogen attack tests if this is not properly recorded in the history, it will be over-
results obtained at about 550 °C and 13.8 MPa hydrogen looked in remaining life assessments. The API RP 573 [64]
pressure and using carbon steel, C–½Mo, and Mn–½Mo steels. describes the recommended practices to inspect heaters
and heater tubes and also provides more detailed descrip-
inspection methods. The API RP 941 includes a summary tions of the causes of deterioration.
of the available inspection methods used, emphasizing the
limitations and detection capabilities. 17.5.3 Carburization, Metal Dusting, Sigma
Phase Embrittlement, and Oxidation
17.5.2 Creep Metals and alloys are generally susceptible to carburization
Creep is a well-known damage mechanism affecting metals when exposed to carbon-rich environment at high tempera-
and alloys operating at high temperatures. Creep rupture tures [65]. Carburization attack is a process whereby the
and cracking develop relatively slowly with time at stress carbon enters and diffuses into the metal and form internal
levels that are lower to those necessary to cause plastic carbides. This is possible because of the high tempera-
yielding. Some construction and design codes establish tures that favor the diffusion process. As a consequence of
adequate design stress based on creep strength. If the carburization, the alloy suffers embrittlement and other
design temperature is below the limits where these metals mechanical property degradation. The carburizing environ-
and alloys are known to suffer creep, the design is then ment in oil refineries is due to the crude oil, its distillates
done in the elastic range, as it would at room or ambient and hydrocarbon gases. Coke formed adjacent to the metal
temperature. surface of tubes is the main source of carbon.
In the absence of corrosion or other damage mecha- There are two main families of steels, namely ferritic and
nisms, alloys operating below the creep regime will provide austenitic. Carbon steel, 1Cr–½Mo, 1¼Cr–½Mo, 2¼Cr–1Mo,
unlimited useful life. Even within the creep regime, if the 5Cr–½Mo, 7Cr–½Mo, and 9Cr–1Mo are ferritic steels. The
temperature is on the low side of the range, the time to solubility of carbon in ferrite is very limited (≤0.02 wt %).
rupture may be so large that it is practical to consider These steels begin to undergo a phase transformation from
unlimited useful creep life. The approach has been to ferrite to austenite when reaching and exceeding the lower
establish allowable stresses as the stress required to cause critical temperature, which varies from about 720 °C to
creep rupture or a given amount of creep strain at the end 825 °C, depending on the alloy content. These steels are not
of so many hours of exposure. In practice, because the used at or near the lower critical temperatures. The limiting
values used in the design are higher than the operating design metal temperature given by API Standard 530 for
temperature and pressure, equipment, piping, and tubes heater tubes alloys is 540 °C, 595 °C, 650 °C, and 705 °C, for
usually exceed the designed life and still may have signifi- carbon steel, 1¼Cr–½Mo, 5Cr–½Mo, and 9Cr–1Mo steels,
cant amounts of remaining life after many years of service. respectively. These limits set the alloy about 120 °C–180 °C
Creep damage can still occur in places of excessive stress below the lower critical temperatures.
concentration or arising because of lack of flexibility in pip- Carburization may start being significant in these
ing but, in general, pressure vessels and piping in oil refin- ferritic steels only above 650 °C–700 °C, but at these high-
eries are designed with overly conservative safety margins. temperature levels the main concern should be strength
Furnace tubes pose a different problem in that the and creep, rather than carburization, except under metal
temperature of the metal is higher than the fluid temperature. dusting conditions. Metal dusting is another form of carbu-
In cases such as a hydrogen manufacturing unit, the rization that generally results in pitting and wall thinning.
temperatures are so high that special alloys are used and It has been reported in catalytic reforming heater tubes,
even so, the tubes have limited life because of creep damage. [66] but it is more commonly seen in chemical process
In general, however, in most common oil-refining pro- plants [67]. Carburization is expected to significantly
cesses, the use of alloy steels is determined more on the increase when ferritic steels reach or exceed the lower
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Chapter 17 n Corrosion Inspection and Control in Refineries 447

critical temperature, but when this happens they would time to failure is reached. The alternative to achieve longer
soften significantly to the extent that they may have insuf- lives would be to upgrade to higher alloyed materials.
ficient strength to withstand normal operating pressure or Inspection for the detection of wet H2S SCC has tradi-
even its own weight. tionally been performed by wet fluorescent magnetic particle
Austenitic stainless steel can be used for temperatures testing (WFMT), but more recently there is an increased use
higher than those allowed for ferritic steels. Typical appli- of alternating current field measurement (ACFM). WFMT

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cation in the oil-refining industry is in furnaces as heater requires cleaning the surface on both sides of the welds
tubes. The internals of fluidized crack cracker unit (FCCU) on the inside of the equipment and consists in applying
regenerators are usually made of type S30409 steel, operat- a fine fluorescent magnetic powder in a liquid medium
ing at about 730 °C, and this selection is made on the basis on the steel surface while also applying a magnetic field.
of strength as well as resistance to sigma phase formation. Surface breaking cracks accumulate this fine powder that
Although carburization does occur in this FCCU service, can be revealed with “black light.” It is a highly sensitive
it is usually shallow. The main degradation mechanism of inspection technique for crack detection. In fact, experience
S30409 steel in FCCU regenerator service is sigma phase has shown that it often detects shallow indications that
embrittlement [68]. Sigma phase is a nonmagnetic inter- disappear fairly easy with light superficial grinding. These
metallic phase composed mainly of iron and chromium scratch-like indications should well be defined as nonrel-
that forms in ferritic and austenitic stainless steels during evant. If this is not done or properly clarified, the inspection
exposure at 560ºC–980ºC. It causes loss of ductility, tough- files would give the impression that the wet H2S cracking
ness, and is generally strain intolerant at temperatures under problem is more critical than it really is because they will
120ºC–150ºC, but it is believed it has little effect on properties contain records of inspections performed and indications
in the temperature range where it forms. If this were so, it found, without qualifying if they were relevant or not. The
would appear that there should be little consequence as long ACFM is an electromagnetic noncontacting technique that
as the affected components continuously operate at the ele- applies an alternating current flow in the skin near the
vated temperature. However, cracking could occur if the com- surface. A magnetic field forms above the surface associ-
ponents were impact loaded or excessively stressed during ated with this uniform current, and this will be disturbed
maintenance work. Sigma phase formation competes with if a surface-breaking crack is present. It is claimed that it
carburization. Sigma phase is usually observed in the bulk of requires less surface preparation than WFMT.
the steel and carburization on the surface where the source of Shear wave ultrasonic inspection is used to size and
carbon is located. Excessive carburization depletes the aus- learn more about crack indications. Automatic ultrasonic
tenitic matrix of chromium and thus weakens its resistance to inspection (AUT) is also being used with the options of
sulfidic corrosion. Excessive wall thinning has thus resulted examining B-scan and C-scan for HIC damage. C-scan is a
because of severe carburization followed by sulfidation. top internal ultrasonic view image of the metal; B-scan is a
through-thickness ultrasonic side image. Visual inspection
17.6 Detection and Measuring is still the most effective way to detect H2 blistering.
Techniques The prediction, detection, and measuring of naphthenic
The techniques and methods used for the detection and acid corrosion have been a challenge. The TAN has tradition-
measuring of degradation of materials depends on the ally been used to indicate the corrosion potential and acid
mechanism and the oil-refining process. In the case of crude content, and although it seems there is general agreement
tower overhead corrosion, common corrosion monitor- that it does not always work to indicate corrosiveness to oil
ing techniques used are the measurement of pH, chemical refining equipment, it is still being widely used today. This
analysis of the water for chloride and metal content, corro- is basically because there is not anything else universally
sion rate measurements on weight-loss coupons or corrosion accepted to use in its place. Alternative methods have been
probes (e.g., electrical resistance probes known as ER used where sulfur compounds are extracted first before
probes), and periodic ultrasonic thickness measurements. measuring TAN in the sample or where the naphthenic
Process simulation [69] has been used to predict where acids are first extracted from the oil sample and then
water condensation and salt precipitation will start occur- analyzed [70]. New approaches have been suggested to
ring and thus better define the corrosion control strategy. measure the naphthenic acid corrosion potential based on
The whole process of controlling and measuring the crude corrosivity tests to obtain an index known as “naphthenic
distillation overhead corrosion is often under the respon- acid corrosion index” or NACI [71] or the concentration
sibility of the vendors of the chemicals that are used for of iron dissolved in the oil sample after exposure to naph-
corrosion control. thenic acid corrosion in Fe powder tests [72]. These two
In addition to the corrosion control programs, there latter methods deal with the complex interaction between
should be an inspection strategy that regularly measures naphthenic acid corrosion and high-temperature sulfidic
wall thickness by ultrasonic devices and, when possible, corrosion. In the former, the corrosion product film is indi-
profile radiography, to detect and measure corrosion on rectly measured and the naphthenic acid corrosion index is
selected places commonly referred to as thickness measure- obtained by dividing corrosion rate by this corrosion prod-
ment locations or corrosion monitoring locations. These uct film weight. The method is based on the premise that
should include all dead legs, injection points, elbows, reduc- naphthenic acid corrosion and high-temperature sulfidic
ers, and tees. Equipment and piping in the crude distillation corrosion are competing processes and that pure naphthenic
tower overhead system should be inspected at every avail- acid corrosion would produce no corrosion product film while
able opportunity. Useful lives of tube bundles and tubes in pure high-temperature sulfidic corrosion would produce a
fin fan coolers in this system should be noted, and replace- corrosion product film. Thus, a low naphthenic acid corro-
ment or retubing should be planned proactively, before the sion index would indicate that sulfidic corrosion dominates,
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448 Petroleum Refining and Natural Gas Processing

a high naphthenic acid corrosion index would indicate that obtained by the fitted curve is taken as the outcome of the
naphthenic acid corrosion dominates, and an intermediate test, about 33 and 220 ppmw for the crude oil in Figure 17.2,
naphthenic acid corrosion index would indicate inhibited a and b, respectively.
naphthenic acid corrosion. This method is based on the premise that naphthenic
Conventional weight loss coupons are used in 48-h acid corrosion produces soluble iron naphthenates while
tests at 260 °C (500 °F) to determine the naphthenic acid sulfidation would produce an insoluble corrosion product.
corrosion index. In the Fe powder test, fine and pure iron Therefore, by filtering out all solids in the oil sample after
powder is used in 1-h tests conducted at temperatures the 1-h test and measuring the iron concentration only in
beginning at 140 °C, then at 40 °C increments through the liquid oil sample, before and after the test, a number
380 °C. Some of the tests in the middle of this temperature is provided that indicates the naphthenic acid corrosion
range are duplicated to increase accuracy in the light of rela- potential. Zero amount of dissolved iron would imply no
tively large data scatter encountered. The amount of dis- naphthenic acid corrosion in the Fe powder test, regardless
solved iron is determined for each test. These experimental of the extent of sulfidation that may have occurred and of
points are plotted and curve fitted, usually with a third or the amount of iron consumed by its conversion to iron
fourth order polynomial equation within the temperature sulfide corrosion products.
range 140 °C–380 °C. Examples are given in Figure 17.2 It was found that the H2S that evolves when heating
for two heavy crude oils. The maximum iron concentration a sample of sour crude oils and sour distillates during the
iron powder test can react with at least part of the iron
a 45 naphthenates that resulted from naphthenic acid corrosion,
introducing an error since it reduced the amount of dis-
40 solved iron that was originally produced by naphthenic
acid corrosion. To assess the phenomenon without the
35
Dissolved Iron [ppmw]

interference of sulfidation, pure liquid paraffin was used

30 together with commercially available pure naphthenic acid.
Extensive laboratory testing and research was conducted
25 and to confirm previous findings made by the Fe powder
tests, conventional autoclave weight-loss coupon tests were
20
performed. Thus, adding 0.2, 0.5, 1.0, 2.0, and 4 wt % naph-
15 thenic acid to this clear mineral oil, the TAN increased from
zero to roughly 0.5, 1.4, 2.7, 5.6, and 11.4 mg KOH/g, respec-
10 tively. Fe powder tests were performed with these synthetic
oil samples and the results were 7, 17, 192, 654, and 3350
5 ppmw dissolved iron, respectively. The standard weight loss
0
coupon tests (48 h each) were conducted using these same
100 140 180 220 260 300 340 380 420 synthetic oil samples. It was confirmed that corrosion rate
Temperature, °C increases with increasing TAN, but the additions of reactive
sulfur species greatly inhibited naphthenic acid corrosion
and modified this apparent TAN-corrosiveness correlation.
Adding elemental sulfur and nonreactive sulfur species did
not have any naphthenic acid corrosion inhibiting effect.
b 300 The inhibiting effect of the reactive sulfur species started to
become evident only at temperatures above 200 °C, when
sulfidation was suspected to start occurring. A great number
250
of sulfur species were tested and, although not expected to
Dissolved Iron [ppmw]

be found naturally in crude oils, butyl and methyl sulfoxide

200 displaced the point of maximum iron dissolution from
about 280 °C–290 °C to 140 °C. This finding was confirmed
by weight-loss coupon tests. At 280 °C, pure liquid paraffin
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

150 with 4 wt % naphthenic acid resulted in a corrosion rate

range of 2.5–3.0 mm/y, in coupons made of carbon steel,
100 5Cr–½Mo, 9Cr–1Mo, and 12 wt % Cr steel. At 140 °C the
amount of dissolved iron in the Fe powder test and the cor-
rosion rate measured in weight loss coupon tests were neg-
50 ligible using this same synthetic oil sample. Adding 0.28 M
(Molar) sulfoxide to this synthetic oil reduced the corrosion
rate to 0.8 mm/year, 0.4 mm/year, 0.3 mm/year, and 0.03
0
mm/year at 280 °C, in carbon steel, 5Cr–½Mo, 9Cr–1Mo,
100 140 180 220 260 300 340 380 420
and 12 wt % Cr steel, respectively. Thus, at this temperature
Temperature, °C they also experienced a naphthenic acid corrosion inhibiting
Figure 17.2—Fe-Powder test results of about 33 ppmw for effect. But at 140 °C, the corrosion rate range increased from
(a) heavy crude oil 15.7 °API, 2.7 wt % sulfur, and TAN 1.3–1.5, practically zero to 1.3–8.7 mm/year for these four different
and 220 ppmw for (b) heavy crude oil 10.8 °API, 2.7 wt % steel coupons. That is, as high or higher corrosion than
sulfur, and TAN 4.6–6.5. before adding any sulfur species but occurring at half the
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Chapter 17 n Corrosion Inspection and Control in Refineries 449

temperature level. This finding, originally made by the Fe oil sample on the metal surface and on refreshing the oil
powder test, demonstrated the complexity of the interac- sample to overcome the loss of TAN that occurred when the
tion effect between sulfidic and naphthenic acid corrosion, naphthenic acids decompose and are consumed during the
which makes prediction rather difficult. 48-h test [74]. The nature, concentration, and composition
The corrosion could then be attributed entirely to of the naphthenic acids differ among different crude oils
naphthenic acid corrosion when these synthetic oil samples with different origins so adding commercially available
with naphthenic acid doses did not have any intentionally naphthenic acids to these crude oils would change this
added sulfur species. It was thus found that 5Cr-½Mo and and render the test useless for the purpose of determining
9Cr-1Mo steels offer some useful resistance to naphthenic which one is more or less corrosive than the other. Velocity or
acid corrosion when the TAN is relatively low (<1.5 mg shear stress is one of the factors that play a role on naph-
KOH/g). For higher TAN, however, they start experiencing thenic acid corrosion in piping and piping accessories, but
unacceptably high corrosion rates. When using the syn- to determine which crude is more or less corrosive than

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
thetic oil sample with TAN = 5.6 mg KOH/g and no sulfur at another, the velocity or shear stress factor should be kept
the same testing temperature of 340 °C, the corrosion rate constant in comparative tests. The longer the test dura-
for 12 wt % Cr steel was 0.5 mm/year. A corrosion rate of 0.5 tion the more likely the oil sample will degrade with time
mm/year would be unacceptable for a 12 wt % Cr steel tray since naphthenic acids and sulfur compounds decompose.
component about 3 mm thick. If naphthenic acid corrosion Lighter products (methane, propane, butane, light gasoline,
occurs on both sides, the tray would disintegrate in 3 years and others) may also separate from the oil sample as they
of service. When using the synthetic oil sample with TAN = leave the solution and vaporize with increasing tempera-
2.7 mg KOH/g and no sulfur at the testing temperature of ture during the tests. To overcome this, some autoclave
280 °C and 340 °C, the corrosion rate for 12 wt % Cr steel tests are performed with a condenser that condenses the
decreased to 0.1 mm/year. This would also be unacceptable lighter products and returns them to the autoclave. How-
for packing material that is usually about 0.5 mm thick ever, the basic issue of being able to discriminate between
or less and would therefore disintegrate in 2 to 3 years of sulfidation and naphthenic acid corrosion is not addressed
service. Based on these tests performed by using the same by any of these methods and for any given amount of dam-
synthetic oil samples for Fe powder and autoclave tests, it age or corrosion there would not be an easy way to assert
was possible to establish a correlation between the amount if it is sulfidation or naphthenic acid corrosion. Tests have
of dissolved iron obtained at any given TAN and the corro- been run to determine by how much the TAN is reduced
sion rate obtained for the same TAN. This is illustrated in because of the test exposure conditions, but KOH is found
Figure 17.3. There was a significant difference in corrosion to also react with iron naphthenates so even if the acids had
rate for a carbon steel tested at 280 °C and 340 °C, but the been completely consumed or destroyed, a TAN of zero will
difference was insignificant for 12 wt % Cr steels. This type not be obtained.
of correlation allowed translating Fe-Powder results into It should also be mentioned that corrosion rate mea-
corrosion rates. For instance, 33 and 220 ppmw dissolved sured in weight-loss coupons has shown a dependence
iron in the Fe-Powder tests in Figure 17.2 would translate on exposure time. The corrosion rate is high with short
into 0.28–0.60 mm/year and 10–20 mm/year, respectively, exposure time and tends to decrease as the exposure time
for carbon steel. In the case of 12 wt % Cr steel, the cor- increases up to a point where it is believed it stabilizes and
responding corrosion rate would be 0.2 mm/year for 220 remains constant. Usually the exposure times are 8, 24, 48,
ppmw dissolved iron. 72, or longer. In comparison, corrosion rate in the field
Several other methods have been proposed to study or on actual equipment and piping is obtained after one or
measure naphthenic acid corrosion where the emphasis is more years in service. Unlike autoclave tests, where the oil
placed on the velocity or shear stress [73] exerted by the sample remains the same during the entire exposure time
and their corrosive species may be consumed, degraded, or
10.0 both, in the field the materials are exposed to the oil that is
continuously replenished. So reproducing corrosion rates
measured in the field by conducting autoclave tests with
Corrosion Rate, mm/year

weight-loss coupons may not always be successful.

Carbon Steel C–½Mo steel used to be selected for some high-
340 °C temperature high-pressure hydrogen service, but this is
280 °C not currently allowed. This created a special challenge in
1.0 that many refineries and chemical process plants still have
C–½Mo steel equipment operating within high-temperature
hydrogen attack conditions above the carbon steel Nelson
curve. The recommendation has been to regularly inspect
12 wt % Cr Steel these assets to make sure they remain free from hydrogen
280 °C - 340 °C attack and replace if damage is found. The API RP 941
describes the most common inspection methods used to
0.1 detect high-temperature hydrogen attack. Advanced ultra-
1 10 100 1000 10000
sonic backscatter technique has found increasing use in
Dissolved Iron, ppmw this respect [75].
Figure 17.3—Correlation established between corrosion rate The task of developing techniques and methods
and Fe-Powder test results obtained by using clear paraffinic that would allow determining if C−½Mo steel can stay
oil dosed with naphthenic acid, no sulfur species added. in service or needs to be removed and replaced is very
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450 Petroleum Refining and Natural Gas Processing

attractive. The concept of “bad M23C6 carbide” was introduced reflux or both, because of the potential to form these
in 1996 [76] and carbide extraction replication was then neutralization salts inside the tower.
used to analyze the type of carbide in an attempt to be In case of encountering wet H2S stress cracking, the
able to tell if that particular C−½Mo steel has high-tem- indications are usually removed by grinding and if the exca-
perature hydrogen attack resistance that resembles the vation is deep weld repair is usually necessary. If the damage
old C−½Mo steel curve or the existing carbon steel Nelson is only in the form of HIC and H2 blisters, a fitness-for-
curve. The presence of bad carbides was supposed to service (FFS) [78] evaluation is normally required to first
indicate similar hydrogen attack resistance than carbon determine if they can be left without removal and repaired.
steel and those not having this bad carbide were likely HIC-resistant carbon steel is often specified, but there have
to still comply with the former Nelson curve for C−½Mo been doubts with increased susceptibility to SOHIC [79].
steel. This approach has been abandoned because it Also, HIC-resistant carbon steel equipment still requires
could not been confirmed and because of contradictory the same kind of inspection for HSC as conventional steel.
results obtained elsewhere. HIC-resistant steels are specially manufactured to have
extremely low sulfur content (typically less than 0.003 wt %),
17.7 Prevention Methods plus the addition of a small amount of calcium (used to
The techniques and methods used for the prevention of the scavenge residual sulfur into a harmless non-planar inclu-
degradation of the material also depend on the mechanism sion) and hence less inclusions and nucleation sites for
and the oil refining process. Water wash is often used in HIC but they can have marked pearlite banding, indicative
oil-refining processes to dissolve contaminants and wash of segregation along which HIC may still form. Carbon
hydrocarbon streams. In the case of crude distillation steel purchased as HIC resistant steel but not certified by
units, the first step used to prevent corrosion is to desalt HIC testing has also suffered HIC in severe service along
the feed and use caustic NaOH injection downstream the the central segregation line. Some refineries prefer to use
last desalter. Desalters remove the salts together with solids standard carbon steel clad with austenitic stainless steel
and sediments from the crude oil but the process is not for severe wet H2S service because of the saving realized by
100 % efficient. Typical target is to reduce the salts to about not having to perform any inspection for wet H2S cracking.
3 ppmw (weight). The injection of caustic into the desalted Corrosion in wet H2S environment does not necessar-
crude oil feed stream is called primary neutralization and ily have to be high for the damage to develop. Carbon steel
it is to reduce the effect of these hydrolyzable salts by con- forms a protective iron sulfide layer that keeps corrosion
verting them to sodium chloride (NaCl) that is more stable, rates low. Therefore, traditional on-stream inspection
does not hydrolyze as much, and stays with the liquid that programs based on periodic ultrasonic wall thickness mea-
falls and collects at the bottom of the distillation column surements to estimate corrosion rates will not give any
that is usually fed to the vacuum distillation unit. Some indication of lower or higher potential for wet H2S damage.
refineries do not use it because Na tends to increase the The same precautionary measures to prevent cracking and
fouling tendency by coke formation in the tubes of furnaces damage in carbon steels as in wet H2S service are applied in
in downstream units. this HF alky service.
Chemicals are added to the crude oil at the desalting Organic thin-film coatings are not normally used to
stage to aid the operation, which uses wash water that is prevent corrosion and hence the wet H2S environment
then removed as brine. Stripped sour water is usually used because they are susceptible to become damaged by steam
as desalter wash water but if excess NH3 is still left in this out procedures. Thermal spraying metals (e.g., Al) on the
water, it may make its way to the crude oil and ends up surface of the vessels could also be used. The success of both
in the tower overhead system. Sour water is the process organic thin-film coating and thermal spraying methods is
water that is collected in refining process units, commonly highly dependent on surface preparation and application;
containing H2S and NH3, and is routed to the sour water failures have been encountered where the coating or the
stripper to remove these contaminants and thus become thermal sprayed skin failed and exposed the base metal to
stripped sour water. corrosion.
Secondary neutralization is achieved by injecting a Water washing is often used in the fractionation side of
neutralizer in the crude tower overhead system. Without in visbreaker, FCC, delayed coker, and fluidized coker units
this neutralization, the pH of the water that condenses in to avoid fouling by NH4HS salts, and this is also beneficial
the overhead system may be as low as 1.0 at spots where to reduce corrosion. In cases where the cyanide content
water starts condensing. At these low pH values, HCl cor- exceeds 20 ppmw, polysulfide injection is also used to con-
rosion can occur at high rates in carbon steel (one or more trol its adverse effect on wet H2S corrosion.
mm/year). Either NH3 or neutralizing amines may be used Historically, NH4HS concentration has been measured
to adjust the pH to about 5.5 to 6.5. The neutralization at the downstream water separator and the values used to
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

product is a solid or molten salt that can cause severe measure corrosiveness of the stream; concentration of 2 wt
under-deposit corrosion in carbon steel and some corro- % or less is found to be noncorrosive to carbon steel. Piehl
sion resistant alloys. Water wash is often used to wash out [80] referred to the Kp factor, which is the product of mole
any salt deposit from the overhead system, in particular % NH3 × mole % H2S, and found that Kp values of 0.1 to
the tubes in the exchangers used to condense the crude 0.5 could be handled with carbon steel, provided the fluid
overhead vapors. A filming amine is often used as corro- velocities did not exceed 4.6 to 6.1 m/s. The rule of thumb
sion inhibitor [77]. Ideally, the salt deposition point should has been to assume 6.1 m/s as the upper velocity limit for
be found downstream the injection point of wash water, carbon steel. Because low velocity could also be detrimental,
and in principle, there should be no direct injection of NH3 in that it could allow deposit formation, a lower limit has
or other amine neutralizer into the tower top, the naphtha also been set at 3 m/s.
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Chapter 17 n Corrosion Inspection and Control in Refineries 451

The measure used to prevent PTA SCC is standard 17.8 Case Study Refinery Material
practice in the petroleum refining industry [81]. The most Problems
common protection method is to use alkaline washing 17.8.1 Vacuum Distillation Unit
involving water with 1 to 5 wt % soda ash (Na2CO3), before The upper packing bed in a vacuum tower severely corroded
opening the equipment and piping to the atmosphere. by NH4Cl salts, indicating the presence of NH3 in the feed.
Some refineries follow these practices of protecting their The tower was being operated with excessively low temper-
austenitic stainless steels in their atmospheric and vac- ature at the top. The source of NH3 could not be accurately
uum distillation units and some do not. In hydroprocess- determined, but the problem was resolved by increasing
ing units there is no question that PTA SCC can become the temperature at the top of the tower to displace the salt
active so soda ash washing the units prior to being opened deposition point outside the vacuum column.
is a common practice in these units. Most refineries apply At least two refineries have experienced high-temperature
the neutralization procedure in their hydroprocessing sulfidic corrosion in 9Cr–1Mo steel vacuum bottom lines
units, irrespective of the operating temperatures, the use when processing a particular heavy (22° API) sour (3.3 wt %)
of chemically stabilized or low-carbon austenitic stainless and low or nonacidic (TAN <0.5 mg KOH/g) crude oil. The
steels, and the feed quality. In the case of furnace tubes, it metallurgical upgrading was made to S31600 to resist it.
is based on the premise that all austenitic stainless steels The indication was that this corrosion was not naphthenic
will eventually sensitize and that there is the risk of PTA acid corrosion but a rather aggressive sulfidic corrosion,
SCC failure. In the case of piping, reactors, heat exchang- and this was confirmed by laboratory tests. Aggressive
ers, and other pressure vessels operating at temperatures
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

high-temperature sulfidic corrosion can cause significant

below the known temperature range for sensitization, corrosion in 5Cr–½Mo and 9Cr–1Mo steels when process-
the concern has been the welds and heat-affected zones ing nonacidic crude oils.
(HAZ). Here again, determining if soda ash wash is still Cases of naphthenic acid corrosion have occurred
required on chemically stabilized austenitic stainless steel when processing crude oil slates made to meet a TAN of
grades can be gainful. 0.5 mg KOH/g or less. Certain West African sweet and light
If materials other than austenitic stainless steels crude oils [82] are well known in this respect, but some
are used in hydroprocessing units in the regions where sweet and light crude oils from South America have also
there is H2S and H2 at operating temperature exceeding been reported to have caused naphthenic acid corrosion
230 °C–250 °C, they should be inspected periodically to [83] at these rather low TAN values. In the light of these
detect high corrosion rates and take the corresponding experiences, some refineries have lowered the limit to 0.3 mg
measures to avoid failures. This is usually done by ultra- KOH/g. These cases of corrosion caused by processing
sonic thickness measurements or profile radiography, low TAN crude oils have been identified because 5Cr–½Mo,
when applicable. 9Cr–1Mo, and 12 wt % Cr steel have suffered corrosion
Many refineries were originally designed and con- with features consistent with what is expected from naph-
structed to process either sweet or only sour crude oils, thenic acid corrosion. These steels are known not to resist
and to begin processing naphthenic acid containing crude naphthenic acid corrosion but are commonly used to resist
oils with these units that are not fully equipped with the high-temperature sulfidic corrosion.
proper corrosion resistance metallurgy for naphthenic The most critical areas for naphthenic acid corro-
acid corrosion has become a challenge. Under modern sion are the HVGO section of the vacuum tower, where
conditions when refineries start processing crude oils or 12 wt % Cr steel random and structural packing material
blends for which they have not yet gathered sufficient field has dissolved; and 12 wt % Cr steel trays, structural sup-
data about corrosion, it is necessary to implement and port beams for trays and packing, and 12 wt % Cr steel
maintain an inspection program to determine the condi- clad have been severely attacked. Likewise, 12 wt % Cr
tion of all lines and equipment operating at temperatures steel vane type vapor distributors, vapor horns, or other
above 230 °C–250 °C where high temperature corrosion inlet devices have also been affected in atmospheric and
could occur. This is intended to identify any locations vacuum distillation towers. The corrosion occurring
that may suffer high corrosion rates and thus ensure the in the internal components of the distillation tower in
integrity of these assets. In cases where corrosion rates crude and vacuum units seems to be the first stage of
higher than normally experienced in the past are detected, manifestation of naphthenic acid corrosion problems.
the forecasted lives should be adjusted accordingly so Vacuum tower design appears to have an effect in that
opportune repairs or replacement can be planned and, 12 wt % Cr steel can suffer severe corrosion in vacuum
in case the corrosion is excessively high, consideration columns designed with packing beds and high wash oil
should be given to metallurgically upgrading to more rates while in older vacuum towers processing exactly
corrosion resistant materials. In the past, S31600 used to the same feed, 12 wt % Cr steel trays and clad survived
suffice, but under certain conditions it also corrodes by without suffering naphthenic acid corrosion [84]. HVGO
naphthenic acid corrosion, if the Mo content is lower than withdrawn from the tower is normally used as wash oil
about 2.3–2.5 wt %. It still offers an excellent corrosion for the lower packing bed when it is still hot and also for
resistance to high-temperature sulfidic corrosion, but if the HVGO packing bed, after the stream is cooled in heat
there is the potential for severe naphthenic acid corro- exchangers. Naphthenic acids distill in the vacuum tower
sion, the current practice is to use S31700 that should and partition into the different streams, depending on
contain 3.0 to 4.0 wt % Mo. If there is potential for any their boiling point. The HVGO is usually the stream that
naphthenic acid corrosion for thin packing material in takes more of the naphthenic acids or the more corrosive
crude and vacuum distillation units, the recommenda- ones. Thus, recycling it back into the tower may actually
tion is to use S31700. increase the amount of naphthenic acids in the column.
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452 Petroleum Refining and Natural Gas Processing

Also, naphthenic acids vaporize and when they condense 17.8.3 Catalytic Reformer
directly on the metal surface of packing, trays, structural The first reactor of a fixed-bed catalytic reforming unit
beams, or clad material in distillation columns, they experienced premature plugging in several occasions,
have a TAN that greatly differs from the TAN of the feed detected by increased pressure drop across the reactor.
that enters the crude unit. Under these circumstances, It was found that the reactor was fouled with a blackish
attempts to establish a correlation between TAN and fine powder. This powder was strongly magnetic and was
actual naphthenic acid corrosion is pointless. The TAN identified to consist of mainly iron oxide. The possibility
of condensing naphthenic acids must be very high and of H2S corrosion in the upstream equipment and piping
probably has little correlation with the TAN of the crude was considered; the resulting iron sulfide could decompose
oil from which it originated. Thus, the naphthenic acid into iron oxide during the regeneration process. A filter
corrosion occurring in distillation tower internal com- system was then installed to trap any corrosion product
ponents differs from that occurring in fully liquid phase from the feed, but the reactor plugging problem persisted.
flow in piping, piping accessories, heat exchanger and The problem was attributed to oxidation of 1¼Cr–½Mo
heater tubes, pumps, and valves. steel piping occurring during the regeneration cycles, with
possibilities of high-temperature excursions causing fur-
ther oxidation on the 1¼Cr–½Mo steel surface. The inlet
17.8.2 Hydroprocessing
piping to the reactor as well as the large and tall feed/efflu-
A pipe failure occurred by excessive wall thinning
ent exchanger (often referred to as the Texas Tower) was
occurring only at the top while at the bottom the corro-
covered with high-temperature oxide scale that detached
sion was practically zero. This occurred in a distillates
relatively easy from the surface. Several oxide scale pieces
hydrotreater unit. The pipe material was carbon steel
were seen inside this exchanger having the exact shape of
ASME SA-106 Grade B. There was a single wash water
the tube outside surface, together with large quantities of
injection point too far upstream of the (REAC) system
iron oxide fine particles. Although not enough to cause
inlet. The long distance existing between the injection
significant wall loss over time, this oxidation occurring over
point and the condensers in a horizontal pipe section
large surface area of the piping and feed/effluent exchanger
allowed enough residence time for the stream to form a
tubes was able to produce enough oxide scale to plug the
wavy stratified two-phase (gas-liquid) flow with the wash
reactor. The catalyst was dumped to remove this fine black-
water occupying the bottom part of the pipe and the NH3/
ish powder; the amount collected was weighed and it varied
H2S laden hydrocarbon gases moving faster on top. The
from 108 to 426 kg. The oxide scale did not necessarily
flow pattern intermittently maintained the upper surface
detach from the steel surface during the regeneration but
of the pipe in wet condition while at the same time the sur-
mainly during subsequent operation, which is why it took
face was subjected to the higher wall shear stress of the
from 6 to 18 months of operation to see the pressure drop
much faster vapor phase flowing on the top half of the
increase from 0.34 to 2.41 bar. At the time, the regeneration
pipe. There was thus a perfectly uniform wall thinning
process was changed from using only air to oxygen, but
along the horizontal pipe section upstream of the reac-
whether this change was responsible for the problem could
tor effluent condensers, including a 90° elbow that also
not be accurately determined. Metallographic evidence was
exhibited wall thinning only on the top half. There was
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

found to indicate that the metal temperatures have greatly

no localized and rough corroded surface that could sug-
exceeded the normal temperature levels of the regeneration
gest salt deposition on the top half of the pipe. The failure
process. High-temperature excursion during regeneration
demonstrated the large influence the flow regime could
was thus suspected to have caused this excessive oxidation of
have on the corrosion of a pipe with two-phase flow in
the 1¼Cr–½Mo steel.
NH4HS corrosive environment. Had the flow regime been
single phase, or nonstratified or annular during service,
there would be no reason why the corrosion occurred 17.8.4 Furnace Tubes Melting from Inside
mainly at the top of the pipe, while at the bottom there In three separate and independent occasions, tube samples
was no corrosion. Injecting wash water that far upstream were submitted to failure analyses in which the tube
of the air coolers created this damaging two-phase flow. showed melting from inside. Metallographic examination
Naphthenic acid corrosion produced iron naphthe- of the solidified metal layer or pieces found inside these
nates that reacted with H2S present in the recycle hydrogen failed tube showed microstructure similar to gray cast iron,
and thus produced iron sulfide that precipitates and were in the case of a carbon steel heater tube, and white iron,
trapped in the reactor [85] of a mild hydrocracker unit, in the case of 2¼Cr–1Mo and 9Cr–1Mo steel heater tubes
resulting in premature reactor plugging. The iron naphthe- [86]. At first, it seemed inconceivable that melting occurred
nates were not produced in the hydroprocessing unit itself inside the tubes while on the outside the tube was still solid.
but came dissolved in the feed from the crude or vacuum The source of heat is located outside the tubes and the tem-
unit where the feed stream was produced. There the corro- perature across the wall thickness should be the same or
sion rate was not high, less than 0.13 mm/year, but this slightly higher on the outside than the inside surface of the
relatively low corrosion rate occurring in long piping circuit tubes. This assumption is still valid. What occurred was that
transported enough iron naphthenates to cause this pre- the melting point of the steel adjacent to the ID decreased
mature reactor plugging. Thus, under these circumstances, significantly because it was first transformed to austenite
although the corrosion rates were relatively low, the piping and then this austenite absorbed so much carbon from the
handling the untreated feed was upgraded to naphthenic coke formed inside the tube that it melted and transformed
acid corrosion resistant steels, S31600 or S31700 steel, not to either cast iron or white iron when solidified.
because of excessive wall thinning but to prevent this During normal operation, the metal temperature of
premature plugging of the reactor.
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Chapter 17 n Corrosion Inspection and Control in Refineries 453

temperature. When the flow through the inside of heater [19] API RP 580, Risk Based Inspection, 1st ed., API Publishing
tubes is interrupted, due to plugging (e.g., coke) or opera- Services, May, 2002.
tional upset (e.g., interrupting the flow), the metal tempera- [20] Hau, J.L., Ledezma, M., and Yepez, U.A., “Material Damage
Implications of Post Weld Heat Treating H2 Blisters in Carbon
ture increases significantly and the ferritic steels may then Steel,” Paper No. 520, CORROSION 2001, NACE International.
transform to austenite under these very abnormal condi- [21] NACE International Publication 5A171 (2001 revision), Materials
tions. At these temperature levels of overheating, the remain- for Receiving, Handling, and Storing Hydrofluoric Acid, NACE
ing hydrocarbon inside the tubes quickly turned into coke International, 2001.
that became the major source of carbon and severe carburi- [22] API Publication 932-A, A Study of Corrosion in Hydroprocess
Reactor Effluent Air Cooler Systems, API Publishing Services,
zation. Carbon solubility in austenite is much greater than in September, 2002.
ferrite. Under conditions imposed by an interruption of the [23] Singh, A., Harvey, C., and Piehl, R.L., “Corrosion of Reactor
flow, the internal pressure in the tubes is absent or fairly low, Effluent Air Cooler,” Paper No. 490, CORROSION 1997, NACE
so none of these tubes ruptured. Once in the austenitic state, International, 1997.
the carbon enrichment process occurred fast in the steel, and [24] Horvath, R.J., Cayard, M.S., and Kane, R.D., “Prediction and
the increase in carbon content reduced the melting point in a Assessment of Ammonium Bisulfide Corrosion Under Refinery
Sour Water Service Conditions,” Paper No. 576, CORROSION

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
manner similar to that described by the iron-carbon or iron- 2006, NACE International.
chromium-carbon equilibrium phase diagrams. [25] Ehmke, E.F., “Corrosion Correlations with Ammonia and
Hydrogen Sulfide in Air Coolers,” Materials Performance.
References NACE International, July, 1975, pp. 20–28.
[1] White, R.A., and Ehmke, E.F., Materials Selection for Refineries [26] Horvath, R.J., and Lewis, K.R., “Implementation of Best
and Associated Facilities, NACE International, 1991. Practices for Water Washes in Hydroprocessing Units,” Paper
[2] Metals Handbook, 9th ed., Volume 13: Corrosion, ASM Inter- No. 654, CORROSION 2003, NACE International.
national, Materials Park, 1987. [27] Toba, K., Ishimoto, H., Murakami, Y., Asotani, T., and Uegaki,
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[8] Gutzeit, J., Crude Unit Corrosion Guide: A Complete How-To [31] Material Selector for Hazardous Chemicals, MTI Publication
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[9] Gutzeit, J., “Controlling Crude Unit Overhead Corrosion –
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Group 274, Effect of Nonextractable Chlorides on Refinery Cor- [33] NACE International Publication 5A171 (2001 Revision), Mate-
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Commonly Used Amine-Based H2S Scavengers on Crude Unit vices, October, 1998.
Towers and Overheads,” Paper No. 571, CORROSION 2006, [36] API RP 574, Inspection Practices for Piping System Compo-
NACE International. nents, 2nd ed., API Publishing Services, June, 1998.
[13] NACE International Publication 8X294, Review of Published [37] NACE International Task Group 174 Technical Committee Report
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International, September, 2003. tional Publication 34101, NACE International, March, 2001.
[14] NACE Standard MR0175/ISO 15156-1, Item No. 21306, 1st [38] NACE Standard RP0198-2004, The Control of Corrosion Under
ed., Petroleum and Natural Gas Industries—Materials for Use Thermal Insulation and Fireproofing Materials – A Systems
in H2S-Containing Environments in Oil and Gas Production, Approach, NACE International, 2004.
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[15] NACE Standard MR0103-2007, Materials Resistant to Sulfide Guidelines for Preventing Stress Corrosion Cracking in the
Stress Cracking in Corrosive Petroleum Refining Environments, Chemical Process Industries,” Materials Technology Institute of
NACE International, 2007. the Chemical Process Industries, Inc., Columbus, OH, March,
[16] Technical Committee Report by NACE International, Materi- 1985.
als and Fabrication Practice for New Pressure Vessels Used in [40] API Technical Report 938-C, Use of Duplex Stainless Steels
Wet H2S Refinery Service, NACE International, 2006. in the Oil Refining Industry, 1st ed., API Publishing Services,
[17] NACE Standard RP0472-2005, Methods and Controls to Prevent May, 2005.
In-Service Environmental Cracking of Carbon Steel Weldments [41] NACE Standard RP0403-2003, Avoiding Caustic Stress Corro-
in Corrosive Petroleum Refining Environments, NACE Inter- sion Cracking of Carbon Steel Refinery Equipment and Piping,
national, 2005. NACE International, 2003.
[18] NACE Standard RP0296-2004, Guidelines for Detection, Repair, [42] Clarke, S., “Stress Corrosion Cracking of Stainless Alloys in
and Mitigation of Cracking of Existing Petroleum Refinery Pres- Oxygenated Caustic Environments,” Paper No. 596, CORRO-
sure Vessels in Wet H2S Environments, NACE International, 2004.
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SION 2000, NACE International.
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454 Petroleum Refining and Natural Gas Processing

[43] API RP 945, Avoiding Environmental Cracking in Amine Units, [65] Lai, G.Y., High-Temperature Corrosion of Engineering Alloys,
3rd ed., API Publishing Services, June, 2003. ASM International, Materials Park, OH, 1990.
[44] Kmetz, J.H., and Truax, D.J., “Carbonate Stress Corrosion [66] Ravestein, M.H., “Metal Dusting in Catalytic Reforming
Cracking of Carbon Steel in Refinery FCC Main Fractionator Furnace Tubes,” Paper No. 496, CORROSION 1997, NACE
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NACE International. Stainless Steel in FCC Service,” Paper No. 06578, CORROSION

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[49] Gutzeit, J., “High Temperature Sulfidic Corrosion of Steels,” [72] Hau, J.L., Yepez, O., Torres, T., Specht, M.I., “Classifying
Process Industries Corrosion—The Theory and Practice, B.J. Crude Oils According to Corrosivity Using the Fe Powder
Moniz and W.I. Pollock, Eds., NACE International, 1986. Test,” Paper No. 699, CORROSION 2000, NACE International.
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Inspection, 1st ed., API Publishing Services, May, 2000. Naphthenic Acid Corrosion,” Paper No. 555, CORROSION
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Hydrogen Free Environment,” presented at the meeting of the [74] Smart, N.R., Rance, A.P., and Pritchard, A.M., “Laboratory
Subcommittee on Corrosion during the 28th Midyear Meeting Investigation of Naphthenic Acid Corrosion Under Flow-
of the American Petroleum Institute’s Division of Refining, in ing Conditions,” Paper No. 484, CORROSION 2002, NACE
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[52] de Jong, J.P., Dowling, N., Sargent, M., Etheridge, A., Saunders- [75] Decker, S., Hynes, T., and Buchheim, G., “Safe Operation of a
Tack, A., and Fort, W., “Effect of Mercaptans and Other High Temperature Hydrogen Attack Affected DHT Reactor,”
Organic Sulfur Species on High Temperature Corrosion in Paper No. 09339, CORROSION 2009, NACE International.
Crude and Condensate Distillation Units,” Paper No. 565, [76] Kimura, K., Ishiguro, T., Hattori, K., Okada, H., Kawano, K.,
CORROSION 2007, NACE International. Yamamoto, H., and Sakamoto, K., “Metallurgical Effect on
[53] NACE International Publication 34103, Technical Committee Hydrogen Attack Damage in C-0.5Mo Steels” PVP-Vol. 336.
Report, Task Group 176 on Prediction Tools for Sulfidic Structural Integrity, NDE, Risk and Material Performance for
Corrosion: “Overview of Sulfidic Corrosion in Petroleum Petroleum, Process and Power, ASME 1996, pp. 8–18.
Refining,” NACE International, 2004. [77] Petersen, P.R., “The Use of Corrosion Inhibitors in the Refin-
[54] Couper, A.S., and Gorman, J.W., “Computer Correlations ing Industry,” Paper No. 594, CORROSION 1996, NACE
to Estimate High Temperature H2S Corrosion in Refinery International.
Streams,” Materials Protection and Performance, January, [78] API RP 579-1/ASME FFS-1, June 5, 2007 (API 579 2nd ed.),
1971, pp. 31–37. Fitness-For-Service, API Publishing Services.
[55] Derungs, W.A., “Naphthenic Acid Corrosion – An Old Enemy [79] Cayard, M.S., Kane, R.D., and Cooke, D.L., “An Exploratory
of the Petroleum Industry,” Corrosion Information Compilation Examination of the Effect of SOHIC Damage on the Fracture
Series (CICS): Refining Industry: Naphthenic Acid Corrosion, Resistance of Carbon Steels,” Paper No. 525, CORROSION
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[56] Babaian-Kibala, E., and Nugent, M.J., “Naphthenic Acid [80] Piehl, R.L., “Survey of Corrosion in Hydrocracker Effluent Air
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1999, NACE International. tional, 1976, pp. 15–20.
[57] Gabetta, G., Montanari, L., Mancini, N., and Oddo, G., “Prelimi- [81] NACE Standard RP0170-2004, Protection of Austenitic Stainless
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644, CORROSION 2003, NACE International. Corrosion Cracking During Shutdown of Refinery Equipment,
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Heaters, API Publishing Services, December, 2002.

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18
Product Analysis and Quality Control
Pradeep Kumar1 and N.S. Murthy1

18.1 Quality Management in Refinery months to a few hours under the concept of the “refinery of
and Petrochemicals—An Overview the future.” This is a seamless integration of all functions
The hydrocarbon industry is more than a century old, and across supply chain management in which feed/product
in the past refineries were built with domestic socioeco- analysis and quality control will play a pivotal role in deci-
nomic considerations in mind rather than creating “world- sion process and timely interventions are essential to obtain
class assets” and competing to achieve the best from the the best from given assets.
bottom of the barrel. Technology incorporations in the Most oil majors have their own research and technology
refineries were again to reduce energy consumption or to wing to support business improvement plans such as testing
comply with statutory/clean fuel needs. In bygone days, of new-generation catalysts; pilot testing of feedstocks to
crude oil refining was confined mostly to fewer process- understand/predict the effects in actual operations; engine
ing configurations, stated on a scale of Nelson’s complex- laboratories to replicate performance of automobile fuels
ity factor, with operations largely routine and refiners in automobiles with respect to durability, comfort, energy
content with lower margins ($/bbl). With successive oil efficiency, and emissions; product application evaluation
shocks in the last 4 decades, refiners have been left with no especially for polymers; and laboratory simulation to assess
option but to try “newer”/tough crudes, which are mostly behaviors such as fouling, coking propensity, compatibility
sour (high sulfur) or have high acidity and added impuri- from likely precipitation of asphaltenes, etc. Furthermore,
ties such as high nitrogen, high metals, high chlorides, a few leading oil companies are pursuing next-generation
etc. These tough crudes, although termed “opportunity technology in the areas of deep hydroprocessing to upgrade
crudes,” bring in new challenges such as mitigating corro- residues and tar sand oil; maximize olefins, especially
sion, sustaining/enhancing product quality, keeping pace propylene and ethylene; convert C10+ aromatics into para-
through plant changes to manage process integrity and xylene; and recover 2,6-dimethylnaphthalene (DMN) from
handle varying yields, controlling pollution/emissions, etc. light-cycle oil for production of plasticizers, etc. All of these
New secondary processing units were added to the refin- green field research techniques need several designs of
ing configuration to process such tough crudes. In short, experiments at a laboratory scale that involve testing, analy-
manufacturing needs “engineering precision” to monitor ses, and quality-control procedures for ensuring technology
and control operations to get the best from any given reproducibility.
crude. Operations needs a “knowledge partner” to perform Clean fuels and biofuels are yet other dimensions to the
to its full potential and close to its capability. All of these refining complexity today. The drives for sustainable mobil-
imply a greater emphasis on stream testing/analysis and ity and, if needed, smoother changeover of energy sources
quality control. are equally compelling refiners to adopt best practices in
With soaring oil prices and worldwide recession cou- analysis and quality control. The repeatability and repro-
pled with the need to restrict/reduce greenhouse emissions, ducibility values are diminishing with the introduction
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there is a paradigm shift taking place in the product mix of newer/smarter techniques by leading institutes such as
from refineries. Furthermore, the cyclic nature of the petro- ASTM. Today, refiners are blessed with test methods that
chemical business shrinks margins of the integrated refin- can detect at the parts per billion (ppb) level. Most test
ing complex. Hence, the cost of quality is being increasingly methods are automated to minimize human errors. Fur-
brought under focus to improve the bottom line, and to this thermore, nonintrusion techniques are gaining acceptance
end an extensive use of online quality measurements and because of the robustness in analysis over a wide spectrum
information technology are being leveraged by refiners. A of quality parameters with inherent precision. Refiners in
typical block flow diagram of a modern refinery and petro- the last 2 decades have maximized online spectroscopy
chemical plant is given in Figure 18.1. techniques.
Refiners are coming under extreme pressure to evalu- “Quality giveaway,” a phrase used widely in refineries,
ate, accept, and process newer feedstocks successfully or is one of the components of cost of quality. It is the extent
with the least effect on plant/process reliability. The key of “quality overkill” above the stipulated specification. It
in this is the response time, and as such several advance- depends on the confidence level in product certification
ments are being tried by refiners to shrink the sampling/ that is based on the competency of the laboratory in testing
testing/analysis of feedstock, which is the single largest a given product with a high degree of precision and close to
time-consuming factor. In fact, a few oil majors are invest- accurate values. It is measured in cents per barrel of crude
ing substantially to reduce crude oil testing duration from processed and can vary from 2 to 10 cents/bbl depending

1
Reliance Industries Ltd., Gujarat, India
455
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456 Petroleum Refining and Natural Gas Processing

Figure 18.1—Block flow diagram of modern refinery. Source: Refinery Block flow from http://en.wikipedia.org/wiki/Refinery.

on the best practices adopted in the field and laboratory operations to exploit the asset’s capability. The central
for quality measurements and control. Unlike petrochemi- laboratory undertakes developmental studies in the for-
cal products, which are predominantly pure components, mulation of “niche products,” newer blend recipes, etc.
petroleum products are a mixture of several hydrocarbons. It has become an integral part of the refining and petro-
Hence, to ensure customers, repeatability and reproducibil- chemical operations and also plays an important role in
ity values are defined for each test method. Refiners stretch troubleshooting. It renders active support by analyzing
their “release specification” of products, which provides trace components, identification of species, diagnosing
their customers confidence so that there is minimal prod- molecular structures of corrosion products, yield loss,
uct quality giveaway. etc. In some refineries the central laboratory undertakes
A quality-control laboratory in a pacesetter refin- statutory requirements of testing and conforming treated
ery will have the capability to test crude and products. effluent quality, assisting air quality monitoring, validat-
In most refineries and petrochemicals complexes, the ing safe disposal of solid wastes, etc. Furthermore, to
central laboratory operates on a 24/7 basis guiding ensure customers of product quality, most quality-control
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Chapter 18 n Product Analysis and Quality Control 457

laboratories undertake “round-robin” tests of a given choice, and the given test has to be performed for contrac-
sample to assess the performance in accurate testing tual agreement with the compliance method. For example, a
ability. The time spent on various activities in a modern refinery may choose an alternative method over the regula-
laboratory is as follows: tory method because the alternative method may be more
• Safety compliance and continual learning—5 % precise or avoid duplication of testing and in the process
• Certification of products—30 % better assists production control. As an example, a correlative
• Customer relations management—5 % spectroscopic method may provide more precise olefin data
• In-process testing—40 % in a few minutes than the labor-intensive liquid chromatogra-
• Crude quality tracking and assay generation—10 % phy ASTM D1319 can in 2 hrs or most automated, time-con-
• Operation guide and QMI certification—10 % suming, multidimensional gas chromatographic techniques.
In short, the central laboratory facilitates refinery and The same correlative analysis might also include benzene,
petrochemical business management to select and buy the aromatics, oxygenates, and distillation points. ASTM D6708-
“best” (value for the money on crude oil/feedstock pur- 07 defines how to assess the agreement between two stan-
chase), operate assets to the “best,” and make customers dard test methods that purport to measure the same property
feel the “best.” Appendix 18.1 provides a “bird’s-eye” view of of a material and how to determine if a simple linear bias
a performance comparison of a quality-control laboratory. correction can further improve the expected agreement.
From a holistic perspective, product analysis provides
18.2 Product Analysis proof of a fuel’s performance on use so as to control the
Fuel quality is important in today’s competitive markets. expected effect on the environment. Most developed coun-
Delivery of products to the customer that are free from any tries are already using ultralow-sulfur fuels and have estab-
contamination or adulteration is the key to maintaining lished work processes to test forecourt fuel samples for
customer confidence and increasing fuel sales. Fuel quality parameters influencing exhaust emissions. Hence, the abil-
compliance does not stop at the refinery gate where fuel is ity for precise testing of fuels is critical to control potential
tested to ensure that manufacturing specifications are met. adulteration between refinery and the point of sale.
After manufacture, fuel is moved to bulk storage depots by The process of error-free product testing starts from
rail, sea, or pipe line and from there on to services stations the initial sample collection, through analysis, to the final
by road tankers. At each stage in the distribution chain reporting and sample retention for checking in case of dis-
there is ample opportunity for fuel quality to deviate. Key putes later. First, a representative sample must be obtained
tests are therefore routinely performed throughout the from the process. Care must be taken to prevent loss of
delivery chain to ensure that product quality is preserved lighter components, avoid contamination, and preserve the
and “fit-for-purpose” product reaches customers. sample for testing. This sample must then be transported to
Refiners today are preparing to meet newer stipula- the laboratory for preparation. For efficiency, a laboratory
tions by way of cleaner fuels and ever-increasingly strin- may break down the sample into smaller portions that can
gent environmental regulatory requirements. The cost of be tested concurrently in different sections.
testing to sustain business can be a double-edged sword. Once a particular method is chosen, it must be cali-
State-of-the-art technology can provide improved measure- brated. For many of the fuel quality parameters (olefins,
ments but at the same time costs in terms of dollars and distillation), gravimetric standards are rarely available and
staff expertise. However, to create a competitive edge in the may not be up to the desired requirements. ASTM D6299,
market, precise product testing by the business is essential standard practice for applying statistical quality assurance
and it has proved to pay rich dividends because of increased to evaluate analytical measurement system performance,
awareness by consumers. Clearly, the best analytical tech- provides information for using various statistical tools to
nology in a laboratory for product testing supported by monitor and control a measurement system, including how
online analyzers is necessary in modern times. to establish reference materials.
Laboratories have been taking a holistic view on mod- It is good practice to validate the calibration robustness
ernization to support manufacturing and the market. Ana- against vagaries seen in sample quality. A change in refinery
lytically, the testing laboratories face new challenges with feedstocks would affect the sample matrix, invalidating the
ever-changing performance goals (raise the bar) to optimize results from a matrix-dependent method.
operation and the supply chain. As a result, reduction of Although over a dozen test parameters may be moni-
quality cost demands better methods with improved preci- tored during a batch formation through blending of several
sion and detection limits. At a very low level of detection, streams that go into the production of diesel or gasoline, the
even sample handling to prevent contamination or loss of challenge is compliance with the sulfur specification of less
the trace analysis has become a concern. For example, with than 10 ppm. Most refiners use online quality measuring
the world migrating to ultralow-level sulfur diesel at less instruments (QMIs) for such compliance, and a laboratory
than 10 ppm, the testing ability within accepted criteria is plays the role of certifying the QMIs. Successful blending
continuously driving the need for new or improved analyti- depends on (1) selection of a reliable online analyzer, an
cal testing methodology. appropriate sample tap, and a debugged sample loop that
To control production, analytical methods must be fast, gives stable and connected signals; (2) operators monitoring
accurate, and reliable. The demand for robust process control instantaneous, integrated values, keeping the overall manu-
to get the best from a given barrel of crude drives the induc- facturing targets in mind; (3) regular spot samples analyzed
tion of better testing methods in the laboratory or online at the refinery laboratory; (4) laboratory specialists perform-
quality measurements directly in the plant. Further, there are ing the analysis and communicating results to operations;
instances when even an alternative method has better reli- and (5) accumulated blending experience and wisdom
ability and accuracy, because of peer pressure or customer
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- to interpret the delta (difference of online minus offline
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458 Petroleum Refining and Natural Gas Processing

v alues), and after a thorough analysis, determining if actions maintained by all players (refinery, marketing, common
are needed. With good laboratory statistical quality-control carriers, intermediates, etc). The sample retention require-
practices in place, the blending process then can be kept on ment for a normal shipment certification sample is 30 days.
track by statistical process control of these deltas over many To preserve sample integrity and prevent loss of light ends,
blends. In total, with a dedicated team, online analyzers can the samples must be sealed and chilled (10°F below ambi-
help the blender face up to the following challenges and ent temperature).
successfully add up to the refinery’s bottom line by way of
• Real-time information and feedback that permits 18.2.1 Product Specification Development
reduction in re-blends and touch-ups and tighter con- and Significance of Analysis
trol for key variables. The petroleum industry is a century old, and product speci-
• Management of quality giveaway for the specification, fications have been formulated and continually improved
which costs the refiners money during blend. upon with decades of experience. Developments in engine
• Accurate and reliable online analyzer performance will technology, newer processes, emphasis of creating value
build the eventual case for a performance-based mea- from waste, newer products especially in the petrochemical
surement system (PBMS). field, ecofriendly mandates, higher conversion/yields from a
An effective product testing/analysis program must also given feed, deeper understanding of raw materials, etc. have
ensure a reliable documentation system, which facilitates facilitated product specification developments. Develop-
quality tracking. Most pacesetting organizations deploy ments of infrastructure such as the express highway, where
LIMS (Laboratory Information Management System). For speed and stability are the critical requirements, have also
regulatory compliance, records must be retained for 5 years added to defining newer specifications such as drivability
from the date of creation (40CFR 80.74—a code of federal index, lubricity, etc., in automobile fuels. Further, several
regulations for housekeeping requirements). There could calculated parameters such as the calculated carbon aro-
be special needs requested by customers. Aviation stan- maticity index, combustion ignition index, Watson K factor,
dards require monitoring of the particulate specification at etc., have been put to use to specify product characteristics.
each step in the supply chain (from refinery units to fuel The significance of each of the properties that must be
in delivery to aircraft) so as to improve product hygiene. tested under fuel specification is briefly described in Table
In such cases, records and retention samples need to be 18.1. The conventional test methods for each property

Table 18.1—Significance and Test Method of Various Product Specifications

Fuel Properties and Significance Test Methods ASTM/IP

Appearance is visually assessed in a qualitative fail/pass test for cleanliness, to preclude free water, D4176
sediments, and suspended matter.

Total acidity of combined organic and inorganic acids indicates the corrosive potential of fuel to metals. D3242/IP354
Trace organic acids can affect the water separation properties.

Aromatic content relates directly to flame radiation, carbon deposition, and smoke. Also affects swelling of D1319/IP156
elastomer in the fuel system. D6379/IP436

Hydrogen content contributes to combustion cleanliness and is broadly related to aromatic content. D3701/IP338

Olefins are unsaturated hydrocarbons that are potential contributors to instability during fuel storage. D1319/IP156

Total sulfur is controlled because sulfur oxides formed during combustion can cause corrosion to turbine D4294, D5453/IP336
blades.

Mercaptan sulfur compounds are limited because they have a very unpleasant odor and attack certain D3227/IP342
elastomer material.

Doctor test detects the presence of reactive sulfur compounds—alternative method to qualitatively D4952/IP30
ascertain mercaptan sulfur.

Distillation curves define the boiling range, which needs to be appropriate for balanced vaporization of the D86, D2887/IP123
whole fuel volume.

Flash point is related to volatility and therefore affects combustibility. It is a leading factor determining the D3828, D56/IP170,
safety in fuel handling. IP523, IP303

Density must be known for weight-loading calculations because fuel is customarily metered in volumes. D1298, D4052/IP365
Also relates to specific energy.

Vapor pressure is significant for wide cut fuels and indicates venting losses of light ends at altitudes and in D5191/IP69
hot climates. Also relates to cold starting.

Freezing point limits higher molecular-weight hydrocarbons that crystallize at low temperatures; it D2386/IP16
therefore influences low-temperature pumpability during flight.

Viscosity affects fuel pumpability over the operating temperature range and relates to droplet size in sprays D445/IP71
produced by burner nozzles. --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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Chapter 18 n Product Analysis and Quality Control 459

Table 18.1—Significance and Test Method of Various Product Specifications (Continued)

Fuel Properties and Significance Test Methods ASTM/IP

Specific energy (net heat of combustion) denotes the amount of heat energy obtainable from a fuel to D3338, D4809/IP12,
provide power (value is calculated). IP355

Smoke point indicates the tendency of a fuel to form soot, which is related to the type of hydrocarbons D1322/IP57
making up the composition.

Naphthalenes are polycyclic hydrocarbons and high in carbon content, exacerbating the problems of carbon D1840
formation, flame radiation, and smoke.

Copper strip corrosion test pass ensures that organic sulfur compounds will not corrode copper components D130/IP154
in the fuel system.

Thermal stability (JFTOT) measurements relate to the amount of deposits formed at high temperature in D3241/IP323
the engine fuel system.

Existent gums are nonvolatile residues left on evaporation of a fuel and serve as a check for contamination D381/IP540
within a product distribution system.

Particulates such as dirt, adsorbent, and rust fines are undesirable and are detected by fine filtration D5452/IP423
through a membrane filter.

Filtration time is measured by the same test procedure as indicated for particulates. D5452/IP423

Water reaction determines the presence of materials that react with water and affect the stability of the D1094/IP289
fuel water interface.

Water separation (MSEP) index rates the stability of the fuel to release entrained or emulsified water when D3948
passed through a fiber glass filter coalescer.

Electrical conductivity needs to be reasonably in line to specification to dissipate electrostatic charges D2624/IP274
generated during fuel handling operations so as to prevent fire or explosion hazards.

Lubricity (BOCLE) refers to the effectiveness of the lubricating moving parts in engine fuel system D5001
components such as pumps and control units where boundary lubrication is a factor in the operation of the
component, thus minimizing wear scar diameter.

Lubricity (SLBOCLE and HFRR) is the ability to reduce friction between solid surfaces in relative motion D6078, D6079
through a combination of hydrodynamic and boundary lubrication, thus minimizing wear scar diameter.

Cloud point of a fuel is a guide to the temperature at which it may clog the filter system and restrict flow; D2500, D3117/IP219
this is increasingly important for fuels used in high-speed diesel engines.

Pour point is an indication of the lowest temperature at which the fuel can be used/pumped. D97/IP15

Cold filter plugging point (CFPP) indicates the highest temperature at which a given volume of fuel fails to D6317/IP309
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

pass through a standardized filtration device in a specified time, thus providing an insight for estimating
the lowest temperature at which a fuel will give trouble-free flow in a certain fuel system.

Carbon residues are values of a burner fuel that serves as a rough approximation of the tendency of the D189, D524
fuel to form deposits in vaporizing pot- and sleeve-type burners.

Carbon residues (micro method) values of the various petroleum materials serve as an approximation of the D4530
tendency of the material to form deposits under degradation conditions and can be useful as a guide in the
manufacturing of certain stocks.

Oxidation stability—distillate fuel oil (accelerated method) values obtained through this test provide a D2274
basis for the estimation of storage stability of the middle distillate fuel such as No. 2 fuel oil.

Oxidation stability—gasoline (induction period method) values obtained through this test provide an D525
indication of the tendency to form gums in storage.

Cetane number (diesel fuel oil) provides a measure of the ignition characteristics of diesel in compression D613
ignition engines.

Research octane number is used by engine manufacturers, petroleum refiners, and marketers as a primary D2699
specification measurement related to the matching of fuels and engines.

Motor octane number is used by engine manufacturers, petroleum refiners, and marketers as a primary D2700
specification measurement related to the matching of fuels and engines.

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460 Petroleum Refining and Natural Gas Processing

are shown and do not take into account any extra margin • ASTM D2699 [Standard Test Method for Research
needed to cover handling losses or repeat determinations. Octane Number (RON) of Spark Ignition Engine Fuel]
The fuel from a nondestructive test (e.g., from the appear- and ASTM D2700 [Standard Test Method for Motor
ance test) can generally be reused for a different test if Octane Number (MON) of Spark Ignition Engine Fuel]:
the sample quantities are limited for conducting product Changes have been made and published to allow for
analysis. the use of automatic octane equipment in conjunction
with the standard Cooperative Fuel Research engine to
18.2.2 Test Method Development produce a research/motor octane number. The octane
ASTM will not adopt a requirement for a property until analyzer is a fuel delivery system that varies the fuel
a “standard” test method has been developed to measure delivered to the vertical jet to produce a maximal knock
that property. The test method development process starts intensity reading. ASTM research report RR-D02-1549
with a technical review of the proposed method. Next, an has concluded that the octane ratings obtained with the
interlaboratory test protocol (round-robin—an oil industry current test procedures and the proposed new autoana-
practice followed by Shell, IP, and customers) is conducted lyzer procedure are statistically equivalent.
in which a common set of samples are sent to a group • Several test methods, i.e., ASTM D482, D1266, D1552,
of laboratories, which independently analyze them. The D3348, D5059, D6334, and D6920, including D6299
results of the participating laboratories are compiled and (Practice for Applying Statistical Quality Assurance
statistically reviewed. If the agreement among the par- Techniques to Evaluate Analytical System Measurement
ticipating laboratories is acceptable, a precision statement Performance) and D6792 (Practice for Quality System
is developed that gives the acceptable difference among in Petroleum Products & Lubricating Testing Laborato-
results obtained by different laboratories on the same ries) under quality control.
sample (reproducibility). • Significant revisions to ASTM D4294 (Sulfur by ED-
Many of the ASTM test methods were developed from XRF) accorded.
the 1920s until now; however, the test methods that are • ASTM D5453 (Sulfur by Ultraviolet Fluorescence) has
based on advancement in new technologies are continu- been revised and published as ASTM D5453-08a with
ally being renewed and adopted. To be sure they remain the following changes:
up to date, ASTM requires each test method to be reviewed • Added note 3 regarding the working standard.
promptly and reapproved, revised, or cancelled. • Scope extended to include ethanol and biodiesel
ASTM Committee D02 on Petroleum Products and fuel blends.
Lubricants meets twice a year—in June and December. The • Deleted precision information appearing previously
committee, with a current membership of approximately against 15.1.1.1 and 15.1.2.1
1500 industry professionals and experts, currently has • New method ASTM D7398 [Test Method for Boiling
jurisdiction over 500 standards. These standards play an Range Distribution of Fatty Acid Methyl Esters (FAME)
important role in all aspects relating to the standardization boiling between 100 and 600°C by Gas-Chromatography]
of petroleum products and lubricants. introduced.
ASTM Committee D02 consists of the following sub- • New method ASTM D7215 (Standard Test Method for
committees: Calculating Flash Points from Simulated Distillation

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
1. Property subcommittees, promoting the knowledge and Analysis of Distillate Fuels) introduced.
development of test methods for specified properties • New method ASTM D7371 (Standard Test Method for
and standard practice, guides, and terminology. Biodiesel “Fatty Acid Methyl Esters content” in Die-
2. Product subcommittees, promoting the knowledge of sel Using Mid-Infrared Spectroscopy, FTIR-ATR-PLS)
the product(s) in the scope. Only product subcommit- introduced.
tees may develop specifications and classifications. • ASTM D97 (Pour Point) sections 6.7 and 8.3.2 have been
3. Coordinating subcommittees, which perform functions revised and published.
that are not covered in the scopes of product and prop- • ASTM D5773 (Cloud Point by Auto Constant Method)
erty subcommittees. sections 7.3, 11.1, 11.2, 11.3, 11.7, and 11.10 have been
D02 Subcommittees meeting December 2007 has reflected revised and published.
the following outcome/changes. • New method ASTM D7397 Standard Test Method for
Cloud Point of Petroleum Products (Miniaturized Opti-
18.2.2.1 Property Subcommittees cal Method) introduced.
• ASTM D909 (Standard Test Method for Knock Char- • ASTM D2533 (Standard Test Method for Vapor-Liquid
acteristics of Aviation Gasoline by the Supercharge Ratio of Spark Engine Ignition Fuels) is no longer used
Method; F-4 engine) is rewritten to align it with form and was therefore withdrawn.
and style nongeneric equipment guidelines. The method • ASTM D445 (Kinematic Viscosity) Grand Design Task
is also updated to include the new engine control equip- Group rewrites the method and precision section to
ment that is available and to remove references for parts include manual and automatic instruments. Prelimi-
that are no longer available. nary data do not suggest any acceptable bias between
• ASTM D7170 (Standard Test Method for Derived Cetane automated and manual data sets.
Number by Fuel Ignition Tester) now includes a full • ASTM D86 (Atmospheric Distillation) has been revised
precision statement after the finalization of the round and published. The main changes are the revision of
robin. Also, between-method reproducibility (differ- section 13 with a new precision and bias statement.
ences between bias-corrected results from ASTM D7170 Other changes include revision to Annex A1 (new pre-
and Test Method ASTM D613) is defined. cision charts); revision to A4.9; revision to 10.2, 10.3,
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Chapter 18 n Product Analysis and Quality Control 461

and X 2.2.2 (reference correct tables); and revision to 18.2.3 Comparison of Test Methods
note 19. Like ASTM, there are other industry standards in petroleum
• A new method is being developed to measure the oxi- testing used by various customers in different countries,
dation stability of gasoline. The method is based on including test methods by IP (Institute of Petroleum), DIN
Petrotest’s PetroOxy (test method to rapidly reduce test- (Deutsches Institut Fur Normung), ISO (International Orga-
ing time for oxygen stability) equipment and received nization for Standardization), GOST (Gosstandart of Rus-
several negatives that will be addressed during the next sia), EN (European), etc. In addition, some of the oil majors
subcommittee meetings. and leading process licensors have developed their own
• A generic method is being developed to use a particle proprietary test methods for the purpose of better under-
counter for gasoline. standing the refining operations. It is a good practice for
• A new method is under development for particulate pacesetting laboratories and refiners who sell their products
contamination of biodiesel. anywhere in the world to have a ready comparison table for
• A new practice is being developed that provides infor- most test methods with widely used ASTM method. This
mation on sampling methods that are useful when vali- helps refiners to serve the customers even if the customer-
dating the performance of process analyzers according specified test method and associated laboratory equipment
to ASTM standard D3764. The new practice also applies are not readily available. On a few occasions it is seen that
to analyzers covered by ASTM D6122. equivalent test methods may not truly represent customers’
needs, and it is worth taking up such issues upfront before
18.2.2.2 Product Subcommittees entering into a sale agreement. Furthermore, making labo-
The main topic dealt with keeping the specifications for ratory personnel aware of intricacies between test methods
motor gasoline (ASTM D4814-11b) upto date with state and is vital for preventing postsale clarifications/litigations.
federal regulations and ensuring that current and relevant Table 18.2 provides an illustration of test methods
test methods are listed. The effect of oxygenates on fuel vola- typically used in oil industries. Please note that it is not
tility and vehicle drivability is always under careful scrutiny. an exhaustive comparison table. However, the most com-
To do this effectively, it is crucial that committee members monly used test methods for fuel products are listed. It is
represent the various industries, from fuel suppliers, ethanol imperative that the laboratories work in tandem with the
producers, supply and distribution, and automotive original marketing/sales team to understand the customers’ desired
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

equipment manufacturers (OEMs). test methods and prepare the laboratory testing accordingly.
Progress on biodiesel continues to generate some positive
momentum as work continues against pressure from regula- 18.2.4 Accuracy, Repeatability, and
tory agencies. Work on the B5 specification under ASTM D975 Reproducibility in Test Methods
remains tabled, and the attempt for a B6-B20 stand-alone The “terms and definitions” related to test methods are
specification now moves to D02 level for balloting. more frequently used to validate the final results. A value
that serves as an agreed-upon reference for comparison is
18.2.2.3 Coordinating Subcommittees derived as:
The activities of this subcommittee are important in 1. A theoretical or established value that is based on sci-
the context of development of standard with respect to entific principles;
product release through QMIs. For ASTM D6299 “Stan- 2. An assigned or certified value that is based on experi-
dard Practice for Applying Statistical Quality Assurance mental work;
Techniques to Evaluate Analytical Measurement System 3. A consensus or certified value that is based on col-
Performance,” several proposals for change were discussed laborative experimental work under the auspices of a
related to run rules of control charts and expressing pre- scientific/engineering group; and
cision as standard deviation of the mean in addition to 4. When 1, 2, and 3 are not available, the expectation of
expressing precision as a moving range of two. The main (measurable) quantity (i.e., the mean of a specified
changes are as follows: population of measurements).
• Control charts are based on series of 20 data points • Accuracy: The closeness of an agreement between a test
instead of 15 data points. result and the accepted reference value. When applied
• Run rules are to be treated as mandatory instead of to a set of test results, the term accuracy involves a
optional. combination of random components and a common
• One run rule was modified, now saying that nine or systematic error or bias component.
more data points falling on the same side of the central • Bias: The difference between the expectation of the test
line are an indication for an out-of-control situation. results and the accepted reference value. Bias is the
• One new rule was added (i.e., seven data points steadily total systematic error as contrasted to random error.
increasing or decreasing is indicative of an out-of- • Intermediate precision: Precision under conditions in
control situation). between repeatability and reproducibility; most often
ASTM D6708 “Standard Practice for Statistical Assessment used for long-term precision in one laboratory and dif-
and Improvement of Expected Agreement between Two Test ferent operators using the same equipment.
Methods That Purport to Measure the Same Property of a • Precision: The closeness of agreement between indepen-
Material: Revision” were approved and published as ASTM dent test results obtained under stipulated conditions.
D6708-07 with the main updates being a more robust equa- Precision depends mainly on the distribution of random
tion for estimating “between-methods” reproducibility and error and does not relate to the true value or the speci-
the term “between-method reproducibility” replaces “cross- fied value. Precision is usually expressed in terms of
method” reproducibility. standard deviation.
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462 Petroleum Refining and Natural Gas Processing

Table 18.2—Product Specifications: Various Test Methods

Jet A-1
Defense Aviation
Standard Turbine Fuel Diesel Diesel Motor Gasoline Motor Gasoline
Tests 91-91 D-1655 EN-590 D-975 EN-228 D-4814

Density D4052 D1298 ISO3675 ISO3675 D1298

IP365 IP160 IP160

Flash point IP170 D56 ISO2719 D93

D3828 IP34

Distillation IP123 D86 ISO3405 D86 ISO3405 D86

D86 IP123 D2887 IP123

Sulfur IP336 D1266 D5453 D1266

D4294 D5453 D2622 D5453

D5453 D3294 D129 D2622

Freeze point IP16 D2386

D2386

Cloud point EN23015 D2500

IP219

CFPP EN116 D6371

Viscosity IP71 D445 ISO3104 D445

D445 IP71

Smoke point IP57 D1322

D1322

Cu corrosion IP154 D130 ISO2160 D130 ISO2160 D130

D130 IP154 IP154

Existing gum IP540 D381 ISO6246 ISO6246 D381

D381 IP540 IP131 IP131

Aromatics IP156 D1319 D1319 IP156

D1319 D1319

CCR ISO10370

IP398

CN EN15195 D613

IP498

Vapor pressure EN13016 D5191

IP394

Oxidation stability ISO7536 D525

IP40

CCI D976

Lubricity D5001 D6079

• Repeatability conditions: Conditions in which independent under repeatability conditions may be expected to be
test results are obtained with the same method on identi- within a probability of 95 %. The symbol is designated by r.
cal test items in the same laboratory by the same operator • Reproducibility conditions: Conditions in which inde-
using the same equipment within short intervals of time. pendent test results are obtained with the same method
• Repeatability limits: The value less than or equal to which
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
on identical test items in different laboratories with dif-
the absolute difference between two test results obtained ferent operators using different equipment.
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Chapter 18 n Product Analysis and Quality Control 463

• Reproducibility limits: The value less than or equal techniques are applied for reviewing the final results. There-
to which the absolute difference between two test fore participation in interlaboratory comparison or profi-
results obtained under reproducibility conditions may ciency testing programs is considered important to validate
be expected to be with a probability of 95 %. The symbol performance of the laboratories.
is designated by R. The laboratory correlation programs in accordance
• Root mean square error prediction: This is an accuracy with ISO guide 43 are aimed at helping the participating
measure and it is expressed in the same unit as the member laboratories to improve their testing performance
variable y to which it relates. The abbreviation used is in reducing the product quality incidents and being best in
RMSEP or RMSP. class regarding product quality giveaway (QGA). The cur-
• Standard deviation: A measure for the deviation from rent benefits of this program are in providing laboratories
the mean (i.e., it is a precision measure and is the with a quality assurance tool for measuring and improv-
square root of the variance), it is expressed in the same ing the precision of their test results. In turn, this leads to
units as the variable y to which it relates. The symbol increased confidence in the integrity of product quality data
is designated by s. The precision of a measurement produced by the laboratory. Other benefits include influenc-
method can be characterized by several different stan- ing standardization bodies to write more realistic and prac-
dard deviations (e.g., the repeatability standard devia- tical methods and to build in accuracy and quality control
tion), the reproducibility standard deviation, and the into laboratory operations by using well-characterized sec-
between-day standard deviation. ondary reference material. However, the potential customers
• Standard error prediction: The standard deviation of the to laboratory correlation program where providing leverage
prediction residuals (difference between reference value to the efficiency and effectiveness can enhance added val-
and predicted values); it does not include the bias. The ues in the product quality management distribution chain.
abbreviation used is SEP. (Note that SEP is frequently These include production of reference samples for quality
confused with RMSEP.) measuring instrument (QMI) implementation and applica-
• Trueness: The closeness of agreement between a test tion, especially with the more modern applications such as
result and the accepted reference value. The measure of near infrared (NIR) and nuclear magnetic resonance (NMR)
trueness is usually expressed in terms of bias. that rely on modeling with real and well-characterized refer-
• Variance: Termed as a measure for precision. Usually ence material.
the standard deviation, which is the square root of the Testing accuracies with a high degree of precision
variance, is used. The symbol is designated by s2. lead to the minimization of product QGA, which in turn
improves the bottom line of the operating units.
18.2.5 Release Specification of Products Laboratories are considered excellent provided they
Because all hydrocarbon product testing involves a bit of remain within (±) twice the standard deviation (R/2.77)2 of
uncertainty owing to limitations in the methods deployed the prime method over the mean values for each test result
(in the form of repeatability and reproducibility values of calculated from the participating laboratories. In a well-
test standards), refiners try to stretch their testing capa- balanced analytical system, z scores should fall outside of
bilities closer to specification limits within their own the following ranges:
laboratory-ascertained repeatability value. Selling the prod- • –2 to +2 in 5 % of instances
ucts closer to specification limits improves the bottom line; • –3 to +3 in 0.3 % of instances.
however, the confidence level in testing products and “releas- In short, the correlation program is used as a quality
ing” closer to specification limits requires close scrutiny. improvement tool to add to the bottom line.
Many refiners take a conservative approach of releasing
products at specification value plus or minus reproducibility 18.2.7 Testing Productivity
limit (depending upon if the specification is the minimum or A high-performing laboratory is essential if refineries wish
maximum limit) so that there is the least chance of the prod- to achieve best-in-class status. However, in addition to oper-
uct failing/crossing limits at the destination. Other refineries ating to a high standard with regard to the integrity of test
may choose their release specification as the specification results, it is equally important that the laboratory service is
value plus or minus repeatability in consultation with their delivered in an efficient and cost-effective manner. Technol-
customers. As such, not all specifications are critical to end- ogy pace and ongoing automation has required great effort
use need and hence such “pushing” close to limits can be associated with laboratory benchmarking and overall pro- --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

accepted. Few other refiners perform quarterly weighted ductivity for better comparison with peers/technical service/
average of supplies and ensure that the average value is consultancy providers with the objective of gaining more
within the specification limit. In short, the release margin insight into the factors that influence laboratory manpower
is decided by every refinery and other confidence-building and efficiency.
measures such as round-robin tests, visits to customers’ Broadly speaking, two main factors that determine the
premises, arranging a walk-through of facilities by custom- manpower in the laboratory are the volume of work (i.e.,
ers, etc., are done to minimize the cost of delivered products. number of samples, test parameters for routine/nonroutine
sample specimen) and the efficiency with which the analyti-
18.2.6 Laboratory Correlation Programs cal function is executed. Laboratory automation has resulted
Ensuring the quality of test and calibration results requires in executing unscheduled requirements, such as operational
that laboratories must have quality-control procedures adjustment, test runs, troubleshooting needs, QMI perfor-
for monitoring the validity of test results and calibrations mance check in addition to maintaining in-house compliance,
performed. The resulting data are recorded in such a way
that trends are detectable and, where practicable, statistical 2
R is reproducibility and R/2.77 is 1s. standard deviation.
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464 Petroleum Refining and Natural Gas Processing

etc., with much faster pace and with the limited manpower critical to the fertilizer industry, the parameters such as vis-
set for optimized sample schedules around the clock. cosity, caloric value, metals, sulfur, pour point, etc., are of
In an ideal refinery, all laboratory testing would be importance to boiler fuels. With poor interactions between
scheduled and routine, with minimal check samples and refineries and marketing in turn with customers, the same
no troubleshooting exercises required. However, in the real grade of furnace oil was being delivered to both market
world this is far from the case. The percentage of nonroutine segments. Because viscosity became the controlling speci-
analytical requirement may vary from 5 to 30 % of the total fication, substantial cutter stock (middle distillate such as
testing. kerosine, jet fuel, and diesel) was getting diverted to meet
The relatively high manhours per normal shift position specification limits. Subsequently, the refiner started mak-
may indicate a significant scope for manpower efficiency ing two grades of furnace oil: one for fertilizer units and
improvements; on the other hand, inclusion of a high level another for boiler fuel for industries. This small act alone
of overtime hours may exacerbate the situation. It is most resulted in a saving of over $7 million per annum by way of
likely that high staff numbers in the testing laboratory are cutter-stock saving.
mainly due to a high number of samples/nonoptimized Inviting customers and walking through the quality-
schedules being analyzed on a yearly basis rather than just control/assurance system provide greater confidence to cus-
laboratory inefficiency. tomers. A transparent approach always delivers results. There
The key indicator for the efficiency of the work execution are instances of asphaltene control requirements in carbon
is the number of tests performed per hour, per person; this black feedstock (CBFS). The asphaltenes in CBFS render
should demonstrate productivity of the analyst staff when hard spots in tires, making them vulnerable to developing
comparing with other laboratories of similar magnitude. cracks during runs. In fact, unusual demands make refiners
Again, this would suggest that the laboratory is not over- look into “best operating days” in the fluid catalytic cracking
staffed compared with the volume of work it has to handle. process to meet the newer specifications. In short, customers
There is no doubt that laboratory efficiency can be improved having the requisite knowledge of manufacturing processes
by increased automation and adoption of new technologies. by which a given product is made and refiners knowing the
critical attributes of a product in its end application are vital
18.2.8 Case Studies from Customer Relations to creating value to customers and suppliers.
Management
The sayings “the customer is always right,” “customer loy- 18.2.9 For Extended Learning in Product Testing
alty,” etc., are always an integral part of business and are Governments worldwide continue to take action to address
even more critical in this period of low returns and intense the major environmental and human health problems
competition. It is a reality that users on most occasions caused by sulfur emissions. For the petroleum industry, this
have not learned the “best” use of products supplied. It is has meant the introduction of stringent legislation to limit
applicable to any products including fuels from a refinery. the allowed levels of sulfur in automotive fuels. Because
On many an occasion there is a tendency to use a same qual- these regulations are set to become even more rigorous
ity product for different end applications and in the process in the future, accurate and precise measurement of sulfur in
customers do not “see” the money going down with no petroleum products has never been more important.
returns. Although most off-shelf tools on customer relations Ultralow sulfur diesel (ULSD) is a standard term that
management (CRM) capture the buying pattern, price sensi- describes diesel fuel with significantly lower sulfur content.
tivity, just-in-time inventory, payment options, etc., there is Petroleum products constitute a significant source of sulfur
hardly any mention or drive on the “right fuel for given end dioxides (SOx) in air. As a result, sulfur content has been
application.” With soaring oil prices, it is imperative that subject to increasingly challenging controls over the last few
the CRM initiatives also probe these aspects and increase decades, resulting on one hand in continuous improvements
value to customers. This can be effectively done through in hydrotreatment technologies and on the other hand in
development of “niche” fuels for a given market segment. analytical techniques to assess the effectiveness of the desul-
Few fuel specifications in different parts of the world vary furization processes used.
substantially, including the developed world, although the Such measures have helped in achieving a dramatic
end use is the same. For example, diesel is widely used in reduction in sulfur deposition worldwide—a 71 % decrease
internal combustion (IC) engines (automotive and station- in SOx emissions from 1987 to 2001 was reported by the
ary), gas turbines, boilers/furnace, etc. Although diesel for World Mineral Exchange. In parallel, automobile manufac-
automotive engines needs to be at prime quality with high turers the world over are developing engines with advanced
Cetane, lowest sulfur, better stability, and a higher degree of emissions control system that require ultralow sulfur fuels
hygiene, etc., the same are not essential for other applica- to sustain reliability.
tions. In other words, understanding the end application at Today, government regulations impose extremely low
the customer premises is as important as having an excellent limits for sulfur in fuel. For example, in the United States,
relationship with customers. On several occasions, “chal- the U.S. Environmental Protection Agency (EPA) has man-
lenging” conventional wisdom or out-of-the-box thinking dated the use of ULSD from the model year 2007. The allow-
has helped to assess the critical properties in fuels, which able sulfur content for ULSD in the United States is now set
could then be optimized within the logistic capabilities. at 15 ppm, down from 500 ppm. The same has been done
To illustrate the gains realized through customer inter- in Europe, and the sulfur specification in European diesel
action, a refinery was supplying the same grade of furnace that was previously less than 50 ppm was lowered to 10 ppm
oil for 10 years that was used as fuel in boilers of various since October 2009. In Asia, many national environmental
industries and as feedstock to manufacture fertilizers in bodies (e.g., those in Taiwan and Singapore) have adopted
other industries. Although the carbon/hydrogen ratio is the Euro V standard.
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Chapter 18 n Product Analysis and Quality Control 465

Benchtop analytical instrumentation such as energy- and petrochemical units deploy a laboratory information
dispersive X-ray fluorescence (EDXRF), wavelength-dispersive management system (LIMS) to facilitate an effective quality
X-ray fluorescence (WDXRF), and ultraviolet fluorescence management system. A well-defined and implemented LIMS
measurement technologies, with their increased resolution, provides an online audit of sample tracking, test bench
detector sensitivity, and precision margins, have provided occupancy, quality control by way of exceptional report-
much relief for measurement of sulfur to the desired level of ing, stream quality variations over time, quality traceability
accuracy in product certification and in satisfying contractual of finished products, testing performance of laboratory
agreement and legislation. The technology is ideal for quality personnel, tracking of laboratory equipment calibration
control and to ensure compliance with international norms, frequency/bias update records, tracking of stored refer-
including ASTM, IP, ISO, DIN, and EPA. Customized/traceable ence sample, etc. A world-class quality system begins with
standards supplied by leading manufacturers and correlation having a dedicated setup for quality management directly
samples in the expected sulfur range assist in making the use under the head of the complex and is an independent func-
of technology more robust and user-friendly. tion having single-point accountability to ensure quality to
customers. The quality-control cell interacts with all stake-
18.3 Quality Control holders through operations, process engineering, planning/
The process of quality control in a modern refinery/ scheduling and shipping, the reliability team of inspection
petrochemical complex can adopt either the Six Sigma and maintenance, statutory bodies, the environmental team,
methodology of DMAIC (Define, Measure, Analyze, the marketing and customer relations team, etc. The key
Improve, and Control) or the guidelines of total quality features of different subsets of the quality-control process
management involving steps of PDCA (Plan, Do, Check, are outlined in the following subsections.
and Act). Although both approaches could lead to similar
end results, the robustness of the designed process and the 18.3.1 Quality-Control Organization
set of key performance indicators to monitor the efficiency This team in a refinery/petrochemical complex is responsible
and effectiveness of the process are the main differen- for providing timely and precise test results, managing labo-

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tiators between a quality-control program in a world-class ratory facilities, supporting the manufacturing processes by
organization and the rest. The process of quality control in way of inputs at a fundamental level of basic science, facili-
best-in-class refineries will encompass the facets given in tating customers’ requirements with product performance
Figure 18.2. features, demonstrating testing methods, participating in
The various elements of the quality-control process are national and international forums of specification and test
elaborated further for the purpose of giving insight into the method development, performing product benchmark-
salient activities that go beneath. Most IT-savvy refiners ing, undertaking round-robin tests with peer laboratories,

Quality-Control Process
1. Set up quality-control
Unit Operations
organization & define
& Stream Quality
role & responsibility
2. Define testing needs
(parameter, method,
frequency, limits) 5. Establish/follow test
equipment induction/
3. Train stakeholders on calibration process
significance of tests to
4. Evaluate & train on business
variables affecting test 6.2 Report exceptions,
accuracy conduct special tests,
assist newer needs
6.1 Conduct test,
validate results,
& provide feedback
6.3 Analyze through
7.1 Conduct proficiency inferential data/QMI &
test at set frequency & control operation
avoid human error 8. Establish procedure
for/post production
7.2 Conduct round-robin correction, if any 9.1 Establish/facilitate
tests to improve testing customer relations
accuracy management
9.2 Certify products
as per market/
customers’ need

10. Conduct quality audit to verify process effectiveness

Figure 18.2—Activities involved in quality control in a typical refinery.

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466 Petroleum Refining and Natural Gas Processing

eveloping and being the custodian of modeling, certifying

d
online QMIs, etc. In short, this team does the “overseer”
function for the quality value chain across the entire manu-
facturing process.
Some of the high-level key performance indicators
(KPIs) routinely monitored under this segment of the
quality-control process are laboratory safety and envi-
ronmental aspects; customer feedback and redressal;
accomplishment rating in industry round-robin tests;
implementation status of audit (internal and external) rec-
ommendations; LIMS uptime factor, laboratory equipment
reliability; personnel productivity and training; market
development with respect to competitive performance of
Figure 18.3—Process capability assessment through measures
products; induction of new tests; initiatives relating to of precision/tolerance [1].
research; improvement in testing and service delivery using
Mfg. Spec, manufacturing specification for any given
quality improvement techniques such as Six Sigma, 5S, and
measurement parameter; Cp, the process capability, is
Lean; new crude assays, etc. calculated from measurement of mean, LSL/USL (lower
Modern laboratories in the refining and petrochemi- specification and upper specification limits), and standard
cal industry will have the capability to test crude oil, deviation of the measured parameter; P, precision of
hydrocarbon streams, and products with most interna- measuring instrument being used to measure the parameter;
tional test methods through ASTM, IP, DIN, UOP, ISO, etc. T, tolerance of measured value within which the process is to
This is essential because different customers have their be operated and controlled i.e. within LSL/USL.
own unique needs in testing. Furthermore, having a clear
understanding of product acceptability criteria by differ-  USL − µ µ − LSL 
C pk = min  , 
ent customers is vital to ensuring the quality of products  3σ 3σ 
delivered. where µ = the mean of the process
Induction of state-of-the-art QMIs has placed consid- σ = the standard deviation of the process
erable resource demand on ensuring the availability and
reliability of a given sophisticated laboratory test appli-
ance. Some of the advanced test equipment that was hith-
erto only seen in research laboratories but is now being Defining test needs, setting up minimal and maximal
inducted in refining and petrochemical units includes limits, etc., requires considerable expertise from operations,
inductively coupled plasma detection, wide-angle X-ray laboratory services, process engineering, licensor inputs,
diffraction, gas chromatography-pulsed flame photomet- factors likely to affect plant reliability, etc. There will be a
ric detection, crude true boiling point testing, low oxy- tendency to state “overkill” on the requirements in the ini-
genate gas chromatography, hot liquid process simulator, tial setting-up phase, which can be tailored to optimum by
etc. With the incorporation of electronics in laboratory addition of new requirements and reducing the frequency
testing, a reliable source of power is another prerequisite. of testing on the basis of steady-state operation. In other
In short, progressive laboratory management has become words, testing needs identification and implementation will
versatile in dealing with multiple challenges from the sup- be dynamic and calls for periodic review (at least once every
plier (for all inputs) and customer (for all outputs) end to 6 months) to keep the business needs focused.
control quality. Tracking the quality of crude oil is another important
activity of a laboratory because 90 % of refiner input cost is
18.3.2 Testing Needs Identification only on purchased crude. Every refiner attempts to widen the
and Acceptance crude choice so that there is adequate flexibility to exploit
Quality control begins with having an in-depth knowledge the delta in crude price between low and high API crudes.
of the refining/petrochemical manufacturing processes, Because crude wells do get depleted, there are variations
listing measurement parameters that are “critical to qual- between batches supplied. When the actual API of supplied
ity” (here quality is in wider spectrum and is inclusive of crude goes down from that used at the time of selection/
stream specifications, processing units’ efficiency and effec- purchase, there is a substantial penalty. Hence, refiners
tiveness, KPIs, and people supporting the unit operation/ either update the crude database once every 2–3 years with
maintenance/rendering services), and assessing Cp—the the latest assays or track quality so as to take up with the
process capability in statistical terms of control variables supplier to appropriately protect refining margins. There are
so as to achieve business objectives throughout the lifecycle several test parameters [such as recovery at 1050°F, total sul-
of the manufacturing complex. Further, defining the inter- fur, total acid number, bottom sediment and water (BS&W),
action through testing needs, test methods to be adopted, etc.] that are tracked for each lot of supply, which is then
frequency of testing, data archiving, control limits, sample compared with an assay database for the extent of variation
conditioning, etc., between manufacturing and labora- and subsequent resolution/claims, if any, with suppliers.
tory services takes into consideration past experience both Reliability is another “watch word” repeatedly brought
within and elsewhere for the similar unit operation. An under focus in refinery and petrochemical plants. The extent
illustration of statistical means to establish the optimal and of degradation of the unit operations requiring periodic
effective testing needs for any given manufacturing unit is downtime to repair/correct/replace equipment, pipelines,
given in Figure 18.3. machines, etc., to bring back to “fit for purpose” is critical
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Chapter 18 n Product Analysis and Quality Control 467

to monitor to avoid incidents. Here again, the material sci- refiners typically incur erosion of margins when there is
ence team under inspection as well as conditioning moni- QGA in products dispatched, as given in Appendix 18.3.
toring engineers for rotary equipment play a pivotal role Improvement in the accuracy of quality measurements
in assigning laboratory test supports in consultation with will also benefit the customers in terms of “true value” on
process engineering team and operations. the assured quality of products, avoiding complaints and
Most petroleum products are a blend of different even at times litigations, allocating useful time to work
streams. The planning and scheduling department that with suppliers for obtaining a higher degree of quality
oversees the day to day intake and offtake movements in consistency in product delivered, etc. Because “zero toler-
consultation with a logistics and inventory management ance” on product quality is a business imperative, labora-
team set up laboratory testing needs. At times when a com- tory personnel also need to be aware of the commercial
mon dispatch line is used, monitoring of the interaction implications.
between successive products being transshipped will also
be critical to avoid quality degradation/product failures at 18.3.4 Parameters Affecting Testing
load points. Hence, laboratory management undertakes a Accuracy—6M Methodology
comprehensive testing requirement study, evaluates the past Because testing effectiveness is very critical to quality
results for optimizing the load, and gets the acceptance of control, most businesses look for factors that could lead
stakeholders to ensure quality control. to errors in testing. To approach the identification of
The bottom line for effective quality control is the parameters that influence testing, one of the best tools is
need for collating an adequate understanding of refining/ the Ishikawa cause-and-effect matrix or 6M methodology.
petrochemical processing schemes by a laboratory manage- An illustration of potential causes that could result in test-
ment team so as to deliver precise test results to its internal/ ing error is given in Figure 18.4. Setting up proper control
external customers. plans for each of the subgroups through mother nature,
man, machine, measurement, method, and material and
18.3.3 Significance of Testing to Business [2] effective training of stakeholders in the quality testing pro-
It is imperative that laboratory personnel are given an cess will enable an error-free testing, in other words, quality
orientation to the effect of testing on business. It is one control.
of the best practices to develop a business environment in On the basis of the complexity of manufacturing units
laboratories because delays/errors in testing could cost the and implications/consequences of test errors, each organiza-
organization millions of dollars. Throughout the petroleum tion can prioritize the mitigation measures from the causes as
business, products are sold in volume, and the sensitivity of indicated in Figure 18.4. Getting the quality system accredited
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a volumetric correction factor involves representative sam- to ISO 7025 is another effective way of ensuring testing effec-
pling, accuracy of density determination, and reporting by tiveness. Refiners perform round-robin tests on a common
the laboratory. Similarly, the BS&W test on crude, especially sample to assess the extent of deviation among laboratories,
heavier crudes (with API less than 15), is tedious and could and this will assist laboratory management in setting the
lead to errors, which can result in lower value realization corrective plans. A few companies participate in Deming or
from crude being processed. Further, with the cleaner fuel Malcolm Baldrige award programs as testimony to exhibit
campaign around the world, there is price parity that is the precision in product testing leading to lasting customer
based on the sulfur levels of diesel. Hence, determination satisfaction.
of sulfur by most modern methods is critical to business.
Examples of other quality parameters of products that are 18.3.5 Test Equipment Induction and Calibration
linked to price are the research and/motor octane numbers Most modern laboratories are designed and constructed
of gasoline, the viscosity of fuel oil, the Bureau of Mines keeping safety and workflow for better productivity in mind.
correlation index of CBFS, the viscosity index of lube base Sample entry, segregation, conditioning, sequence of test-
stocks, the purity level of petrochemical products, the total ing (destructive and nonintrusive), archiving of samples to
paraffins of naphtha, etc. comply with contractual obligations, and safe disposal of
Appendix 18.2 provides an illustration of improvements used samples follow a preset path in laboratories. Because
of repeatability (r) and the reproducibility (R) of some of the the laboratory environment should be conducive for bet-
tests important to business. In fact, test standards are con- ter productivity, the quality management team emphasizes
tinually updated by global standards agencies such as ASTM, good layout of laboratory testing equipment, incorporation
IP, etc. The scientific community works in liaison with labo- of a 5S concept right from the design stage, adherence of
ratory tests equipment manufacturers and conducts tests ambient air quality in testing areas, well-defined sample
with newer generation methods, and r and R values are cap- container movement, display of supercritical test equip-
tured to verify the test robustness before acceptance. ment operating/calibrating procedures as a ready reference,
As can be seen from Appendix 18.2, the quality of mea- online tracking of samples, data warehousing, environmen-
surements has improved over the years with the incorpora- tally friendly disposal of laboratory wastes, fire prevention
tion of newer and better test methods. This improved quality and proofing features, emergency safe exit, etc.
has benefited suppliers and customers. At the suppliers’ Each country sets its own standards/codes and best
(refiners) end, lower r and R in a test method help to improve practices for safety in petroleum laboratories. Hence, any
the bottom line by way of reduced QGA in sale and the “cor- new tests being introduced go through a systematic protocol
rect” value for the money paid in crude purchased. Refiners of series of actions to be taken through space assessment,
have their own in-house program to evaluate the extent of power and utility requirements, sample conditioning need,
quality overkill in supplies such as cents per barrel of prod- reference sample, post-test cleanup, LIMS connectivity, fail-
uct/unit of measure in a given specification. For example, ure modes and effects analysis to handle potential incidents,
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468 Petroleum Refining and Natural Gas Processing

C & E fish bone-diagram of factors influencing laboratory testing

Material Method Measurement
Shelf life of laboratory chemicals Incorrect method
Outdated method Use of correct units/factors in calculations
Wrong samples Precision of stop watch
Contaminated sample Poor sample conditioning
Poor repeatability of tests Counting errors
Sample weathered Tests based on smell & visuals
Hygiene of laboratory instruments Improper calibration
Outdated sample Testing sequence of a sample Error in testing
Wrong time stamp Poor cleaning of strips, balls, etc. accuracy
Failure of P&U during testing Drift during calibration cycle
Software bug in laboratory equipment Level of motivation Laboratory correlation to get inherent bias
Interference by unknown species Level of training Nonavailability of correct spares
Components malfunctioning (thermostat, spectrum, etc.)
Atmospheric correction
Exhausted columns (in GCs)
Use of incorrect or wrong reference samples for calibration
Error in reference method itself
Upkeep of laboratory equipment

Mother Nature Man Machine

Stakeholders Operations Process engineering

Marketing including forecourts Reliability maintenance
Planning & scheduling Inspection
Supply & trading Research & development
Figure 18.4—Potential error possibility in quality testing.

operating spares and consumables, customer confidence and feedback is provided. It is a common practice to retest
enhancement plan, setting up calibration frequency, statu- through a check sample for correctness of the tests.
tory clearances, if any, etc. In short, every activity in a labo- To obtain precise validation, it is imperative that the
ratory has a bearing on quality control and it is done after a time of the sample is correlated with the then operating con-
good conceptualization starting from “critical to quality.” It ditions of the unit with due adjustment to process lag in the
is again a best practice to have an operating manual written system. The concept of using a barcode has become the boon
by users so that the nitty-gritty in effective use of test equip- to quality control because exact timing of sample collection
ment is well documented and consistently used. can be placed, setting aside potential human error in the vali-
With regard to calibration of any test equipment, some dation of laboratory tests. Further, the new-generation LIMS
of the traits of a good laboratory are display of acceptance has the provision to “lock” test results entering into the LIMS
criteria (normally it is within ±1 standard deviation) and database out of “calibration overdue” instruments. These are
trends of past calibration just over the test equipment, time some of the ways to ensure better validation of test results.
stamp of the next calibration due, having master/reference Some refineries extensively use online QMIs/analyzers;
laboratory instruments wherever applicable to calibrate the even product certification and dispatch is conducted based
rest, assisting calibration by proven/skilled laboratory pro- on such instruments. In such a setup, the role of the labora-
fessionals, tracking of calibration status, etc. Depending on tory is predominantly to move from certification of products
the manufacturing process needs (wherein the test is being to certification of QMIs. Here again the principles of good
performed), the calibration frequency can be optimized. upkeep, calibration of QMIs, performance auditing, etc., are
followed rigorously to ensure quality control.
18.3.6 Testing, Validating, Reporting, and
Ensuring Quality Control 18.3.7 Proficiency Tests and Round-Robin
Apart from standard calibration of test equipment, a few Evaluation
pacesetting laboratories have a system of validation of test Proficiency tests and round-robin evaluation are the two crit-
results through an inferential method of manufacturing ical parameters required for quality control and have been
plant data. It is a routine practice in hydrocarbon indus- dealt with in great detail in the previous section. Because
tries to correlate the operating parameters with laboratory the strength of any process is determined by its weakest link,
data and formulate a statistical equation to predict stream laboratory personnel proficiency in testing “accurate” on a
critical properties such as density, distillation/cutpoints, key sustained basis is very important for assuring internal and
component strength, sulfur, freezing point, flash point, etc. external customers on quality inputs. Compliance with ISO
[3] Online computing has grown versatile with the enormous 17025 systems will assist development of the required overall
capability in servers and a greater understanding of process proficiency of a laboratory team. Few refiners have a techni-
dynamics. Validation of laboratory tests has become an cal services agreement with some of the oil majors, which
integral part of the checks before making changes in plant again shall facilitate laboratory productivity, a key to quality
conditions. Refiners and petrochemical units are exploiting control. In addition, participating in national and interna-
advancements in process automation and taking it to the tional forums on test development, continuous update of
next level of real-time process simulation and monitoring testing capability with new-generation methods, interaction
using a model-based approach. These models predict for a with test equipment vendors, refresher courses, etc., are
given feed the properties of product streams under varying some of the traits used by pacesetting laboratories to stay
operating conditions. Thus, laboratory tests are validated ahead and provide impeccable services in quality control.
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Chapter 18 n Product Analysis and Quality Control 469

18.3.8 Quality Cost It is normally the onus of the supplier to ensure qual-
The quality cost is critical to the hydrocarbon business and ity delivered right up to the customers’ premises. In other
every refiner tries to reduce the delivered cost to customers. words, the best practice is to ensure quality until the door of
Quality cost is one such component and it can typically vary the customer. In short, effective CRM will also alert product
from 2 to 25 cents/bbl of crude processed. The elements of quality practitioners to look at systemic failures and thus
quality cost are reblending, reprocessing, downgrading to a improve the overall business.
lower-value product, yield realized versus potential planned, A modern quality management system will comprise
QGA or quality overkill, in-process inventory due to delays documented quality policy, quality control in the manu-
in batch formation/certification time, rework, pilferage, facturing process, product safety features and handling
evaporation loss, underfreighting, discounted offer to cus- practices, customer engagement practices, laboratory
tomer due to being off specification in one or more param- accreditation process, etc. Although no business house
eters, and product return from customer. could afford conflicts with customers, having a quality
Pacesetter refining companies monitor each and every complaint-handling procedure as part of a quality manage-
batch to minimize quality cost and undertake several initia- ment system is essential and is shared with customers. The
tives for performance improvement. Some of the exemplary main objectives of a complaints procedure are to satisfy
work done by refiners to reduce quality cost are online the customer and not to prove them wrong. However, there
blending and certification, deployment of Lean Sigma to are instances of no real problem, and a simple education
streamline the certification process, use of the Kano model3 in testing procedures has resolved many conflicts. Further,
in creating “value” to customers for the given product; per- increased processing of opportunity crudes in the refining
forming quality chain audits to preempt failure potential diet, use of chemicals for enhanced oil recovery in oil fields,
and take proactive actions such as additional field tests, handling of different products in similar containers to opti-
inferential predictions, product quality tracking across the mize shipping cost, etc., add to contaminants in products
delivery chain, etc. (even at parts-per-million levels), which requires newer ways
The quality cost with respect to yield versus potential is to mitigate complaints.
routinely assessed, and a variance report is critically moni- Additionally, complaints do not relate only to the speci-
tored for bridging the gap. This is often one of the major fication; many complaints relate to understanding different
elements in the overall cost of quality. Leading refinery parameters of the specifications. Hence, it is imperative that
houses use model-based software tools to verify the plant the frontline staff are provided with adequate information
behavior and take appropriate corrective measures. In short, on the product features, inputs on frequently asked ques-
the pacesetting quality-control program that is to sustain tions, product manufacturing process, in-process quality
the business also encompasses quality cost aspects so as to control, and the quality management system in place to
reduce the delivered cost of products supplied to customers. ensure and protect the customer’s interests.
An effective CRM program must include visits to the
18.3.9 Customer Relations Management customer site as required, and potential actions should be
Although the importance of CRM and a couple of case stud- taken to resolve the problem in one visit. Frequent visits
ies have been already dealt with in previous chapters, the to resolve a problem project a poor image of the techni-
different facets of CRM are outlined here. An effective CRM cal problem-solving ability of the organization. Samples
program begins with customer enrollment and continues should only be taken for evaluation as a last resort. The
until the supplier and customer are engaged in business taking of samples adds complexities and a certain degree
transactions. Every business process for its effective deploy- of uncertainty associated with the interpretation of results.
ment requires KPIs that are measurable and well understood Where the complaint relates purely to a measured quality
by each stakeholder of the process. Because quality control or quantity, consideration must be given for application
is the primary focus, customer engagement relating to it of ISO4259, a complaint resolution procedure. One of the
is dealt with specifically. A pacesetting organization first best practices is to regularly review complaints and, when
prioritizes customer engagement considering aspects such necessary, use tripartite (manufacturing including labora-
as the degree of importance to business volume; competitor tory personnel, marketing, and the customer) investigation
strength in making inroads into its own customers; alterna- to avoid recurring failures. The customer is generally not
interested in internal changes or corrective actions taken,
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tives available to the customers (e.g., a gas turbine can be

run on different fuels starting from natural gas, naphtha, but they should be reassured that the incident will not occur
kerosine, diesel, light cycle oil, etc.); criticality of product again. In short, refiners and petrochemical manufactur-
quality to the customers’ business, and the size of sale vol- ing teams have much to learn through effective customer
ume per transaction, which helps to optimize logistics cost. engagement.
Furthermore, defining the product specification parameters
critical to quality, agreed test methods to measure quality 18.3.10 Quality Audit
norms, sequencing of product upliftment, in-transit quality- A quality audit is one of the provisions in the quality man-
control needs, tracking of quality over time, complaint agement system to assure the management on a proactive
handling procedure, etc., are well documented as part of the basis of the effectiveness of the internal processes delivering
agreed-upon business transaction. value to customers. Typically, the audit scope covers each
and every element of the quality delivery chain starting from
3
The Kano model is a theory of product development and customer
the formulation of an agreed-upon specification between the
satisfaction developed in the 1980s by Professor Noriaki Kano that supplier and customer with appropriate test methods, inter-
classifies customer preferences into five categories: attractive, one- nal checks and balances to produce and deliver on-grade
dimensional, must-be, indifferent, and reverse. quality products all of the time, interaction with customers
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470 Petroleum Refining and Natural Gas Processing

on a preset cycle to enhance value in the business transac- menting this chapter could not be accomplished: Reliance
tions, prearranged visits between the two, training and Jamnagar Refinery management for sharing excerpts from
refresher courses, participating in round-robin tests with the internal quality management processes and best practices
peer laboratories and lesson deployment from feedback, in product analysis and quality control, the Six Sigma team
conflict resolution methodology, etc. Further, the quality at Jamnagar for having given the cause-and-effect matrix on
audit must examine the understanding of the importance of potential error in product testing, and fellow colleagues with
quality control and its implications at a grass-root level of the Jamnagar quality-control/assurance team who helped in
production. The audit should also look into the effectiveness the preparation of this document.
in handling customers’ complaints. Pacesetting organiza-
tions conduct two to three quality audits to assure manage- REFERENCES
ment of the overall excellence in quality delivery. [1] Published literature downloaded from internet on typical refin-
ery block flow diagram, Six Sigma lessons (Cp Vs % P/T chart).
Acknowledgments [2] Rand, S.J., ASTM MNL 1, 8th Ed., Significance of Tests for
Petroleum Products, West Conshohocken, PA, 2010.
The authors wish to express their sincere thanks to the fol- [3] Hydrocarbon Processing Magazine, www.Hydrocarbon
lowing, for without their help and encouragement, docu- Processing.com.

Appendixes

Appendix 18.1—Performance Comparison of Quality-Control Laboratories

Categorization of Quality-Control Laboratory

Attributes Good Pacesetter World Class

Number of tests per hour per person 2–3 3.5 4+

Test precision in standard deviation a

~ <1s <1s

Support to operations on product quality/ Limited feed-forward + Build blend models + Migrate to QMI
certification inputs certification

Quality management system ISO9001, 17025 + Track PQ through LIMS + Mostly automated
laboratory

Compliance to specification Participate in round-robin + Take customer care + use Kano model to add
tests program spec

Product certification time ~ 2–3s 4+s

LIMS uptime ~ 99+ 100

a
The standard deviation represents 1 divided by 2.77 of reproducibility
i.e., 1s = R/2.77

Appendix 18.2—Illustration on Test Method Precision Improvement

Repeatability Reproducibility
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Product/Test Specification Year Published Method r % R %

Jet/sulfur 0.3 % wt max – –

2003 D4294 ±0.014 ±0.043

Diesel/sulfur 50 ppm max 2006 D3120 ±4.3 – ±26.1 –

2008 D5453 ±2.2 49 ±19.1 27

Diesel/Cetane index 46 min – –

2004 D4737 ±0.3 ±0.7

Gasoline/benzene 1 % vol max – –

2007 D3606 ±0.04 ±0.18

Naphtha/total paraffin 74 % wt min 2003 D6293 ±0.97 – ±3.9 –

2004 D5443 ±0.55 43 ±1.46 63

Crude oil/density As – –
o
API
1999 D1298 ±0.2 ±0.5
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Chapter 18 n Product Analysis and Quality Control 471

Appendix 18.3—Typical Cost of Quality

Giveaway
U.S. Cents/bbl/
Attributes Unit Unit Change

Diesel cloud deg C 30.5

Diesel of 50 ppm sulfur ppm 6.2

Diesel 10 ppm sulfur ppm 98.6

Diesel CFPP deg C 0.8

Diesel CN Number 6.6

Diesel T 95 % (50 ppm) % 52.5

The data presented above can vary between refineries because they
depend on refining configuration and delivered cost of crude oil.
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19
Fuel Blending Technology and Management
Suresh S. Agrawal1

19.1 Introduction operate blending in a hybrid mode, for example, combining

A typical crude oil refinery produces 100 or more different run-down blending with component tanks to debottleneck

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
product grades, and only a few of them are sold directly as the limiting constraints on one or two components. Exam-
they are produced by the various process units. Most of the ples of batch blending are gasoline, fuel oil, and bitumen,
products sold by a refinery are the blended products made whereas kerosine and diesel blending are usually done in
by mixing several refinery intermediate products to meet run-down blending mode.
the end-user specifications and demands. Refineries earn Sequential blending is time-consuming, manually oper-
as much as 60% of their revenues from the blended prod- ated, and often results into reblends or quality giveaways.
ucts. Examples of blended products are gasoline (Mogas), Batch blending, if properly designed and operated, can be
diesel (middle distillate), fuel oil, jet fuel, bitumen, etc. In very flexible, efficient, and improves refinery profitability.
fact, a refinery produces approximately 65–85% of its end On the other hand, run-down blending is a continuous
products by blending 6–12 components or stocks of differ- process and can be very interactive, complex, and less
ent monetary and quality values to meet 6–10 end-product flexible in terms of the manipulation of component ratios.
specifications. Figure 19.1 shows that a barrel of oil gener- Table 19.1 shows the detailed comparison of sequential,
ates products that constitute approximately 40–50% gaso- batch blending, and run-down blending.
line, 20–25% diesel, 5–10% fuel oil, and the remaining of Figures 19.2 and 19.3 show examples of inline batch
other light- and heavy-end products. blending (tank to tank) for gasoline and multiheader run-
These blended products are made in “offsite” areas of down blending (process units to tanks) for distillate or
the refinery and hence are a part of offsite operations, com- diesel fuels.
pared with process units, which are a part of “onsite” opera-
tions. As simple as it may seem, the blending operation is 19.2.2 Fuel Properties
technically complex; time-consuming; manpower intensive; Although the properties of petroleum products are dis-
and, last but not the least, can affect the refinery’s bottom cussed in detail in an earlier chapter, we will just list the
line because of inefficient operation, excessive quality major properties of fuels in this chapter for the sake of
giveaways, reblends of products to meet the specifications, completeness.
poor quality and inventory data, and lack of coordination
between the planned and actual blend lifting schedule. 19.2.2.1 Gasoline Fuels
This chapter is devoted entirely to all aspects of fuel This section discusses the major properties of gasoline fuels
blending and will discuss blending configurations; blend and their effect on gasoline engine performance and emis-
models; and integration of blending equipment, software, sion considerations.
hardware, and analyzers, etc., from the design consider- • Octane number: A measure of a fuel’s resistance to an
ation points of view. The chapter will also discuss the eco- abnormal combustion condition called knocking that
nomic justification of a blending project and methodology is determined by a simple mixture of n-heptane and
to assess the current state of blending operations and suc- isooctane. For example, a 90–10% mixture of isooctane
cessful phase-wise implementation of a blending project. and n-heptane has an octane number of 90, and any
gasoline fuel knocking at the same compression ratio
19.2 Overview and Fundamentals has the same octane value. The antiknocking property
19.2.1 Modes of Blending is represented by three numbers: RON (research octane
There are two types of blending operations, usually referred number), MON (motor octane number), and PON
to as sequential blending and inline blending, in the refin- (pump octane number). RON measures performance
ing industry. Inline blending is further divided into batch at normal road conditions, MON is indicative of high-
blending and run-down blending. Unfortunately, these speed performance, and PON is the arithmetic average
terms are used interchangeably in the industry; therefore, of RON and MON. PON is also sometimes referred as
we will clarify them here because they will be used repeat- AKI (antiknocking index) or RDOI (Road Octane Index).
edly throughout this chapter. In sequential blending, com- • RVP (Reid vapor pressure): A measure of the vapor pres-
ponents are blended one at a time, whereas inline blending sure that fuel exerts at 100ºF and can pressure up a gas
simultaneously mixes all components. Batch blending is tank in summer at high temperature and can boil in
referred to as blending in which the sources of components an open container and create air pollution problems.
are tanks, and run-down blending mixes the components In winter, it must have minimum value for proper fuel
coming directly from process units. It is also possible to vapor pressure.
1
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473
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474 Petroleum Refining and Natural Gas Processing

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Figure 19.1—Representative product distribution from a barrel of oil. Source: Reproduced with permission from [1].

• Distillation points: The ASTM distillation point curve 19.2.2.2 Diesel Fuels
governs the ease of starting, warm-up, mileage econ- • Flash point: The minimum temperature at which the
omy, and performance. The distillation point curve fuel will ignite; its minimum requirement is essential
values are different for common vehicles versus high- for proper safety and handling.
speed racing cars. • Low-temperature operability: Two properties—cloud
• Sulfur: This signifies the importance of vehicle emis- point and cold filter plugging point (CFPP)—character-
sions for lower air pollution of sulfur dioxide (SO2) by ize the operability of diesel fuel. Cloud point is more
burning sulfur (S) and also affects the emissions of car- important for a refinery’s quality-control test, and
bon monoxide (CO), hydrocarbons (HCs), and oxides CFPP is for the low-temperature performance of an
of nitrogen (NOx). engine without plugging its filters.
• Aromatics and olefins: Although they are desirable for • Cetane number/cetane index: The relative measure of
their octane value, they lead to engine deposits and delay in engine starting, rough operation, noise, and
increased emissions of ozone, forming HCs and toxic exhaust smoke. Engines operate better with higher
and carcinogenic benzene in the exhaust.

Table 19.1 Comparison of Various Blending Configurations

Design Aspect Gasoline Diesel Kerosene Fuel Oil

Mode of Sequential or inline batch Sequential, inline batch, or Sequential, inline Sequential, inline
blending run-down batch, or run-down batch, or run-down

Multiheader Rarely Single grade (inline batch), Multiproducts (run- Single grade (inline
blending multiproducts (run-down down blending) batch), multiproducts
configurations blending) (not common)

Typical numbers 6–10 (naphtha, reformate, 6–8 (CDU middle distillates, 3–4 (CDU kerosine, 4–6 (light cycle oil,
and types of FCC, HDS, isomerate, hydrocracking streams) hydrocracker slurry, base fuel oil,
components alkylate, butane, isopentane, kerosine, light diesel) etc.)
Merox, MTBE, etc.)

Types of products Regular (78–82 RON), Light and heavy diesel, Aviation fuels LSFO, HSFO, Marine FO,
premium (83-90), super marine diesel, low- and high- (Jet, JP) bunker FO
premium (91–98) sulfur diesel

Number and RON, MON, RDOI, RVP, Cetane index, pour point, Freeze point, flash Viscosity, API gravity,
types of distillation points (10%, 30%, cloud point, freeze point, point sulfur, flash point, pour
specifications 50%, 70%, 90%), sulfur, API flash point, sulfur, viscosity, point
gravity, aromatics, olefins, 90% distillation point, CFPP,
benzene, TOx, NOx, VOCs API gravity, aniline point

End uses Cars, small vehicles Commercial vehicles, Aviation industry Boiler, furnaces, ships
construction equipment
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Chapter 19 n Fuel Blending Technology and Management 475

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Figure 19.2—Inline gasoline batch blender. Source: Reproduced with permission from [1].

Figure 19.3—Multiheader distillate run-down blender. Source: Reproduced with permission from [1].

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476 Petroleum Refining and Natural Gas Processing

cetane number. The cetane index is another indication

Specification Unit Minimum Maximum Range
of what the base cetane number represents. API Gravity x x 33-44
• Sulfur: Important for reducing the particulate matter Flash Point °C x 35-55
and toxic gas in the exhaust emissions. CFPP °C 309
• Distillation: The ASTM distillation curve measures the T10 °C 190-225
range of temperatures over which the fuel will turn to T50 °C 425-530
vapor. It indicates the lower toxic emissions at idling T90 °C x 260-330
conditions and better engine performance at driving Cetane Number x 43-55
conditions. Cetane Index x 40-45
There are also other important properties such as kine- Sulphur ppm x 15-5000
matic viscosity, ash content, water and sediment, lubricity, Viscosity cST @40 °C x x 1.3-4.5
detergency, etc., that are included in fuel specifications. Lubricity Microns 520
PNA wt% 3.5
Nitrogen ppm 500
19.2.3 Typical Fuel Specifications ASH % Mass x 0.01-0.03
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Fuel specifications have evolved and tightened over the last

several years in the United States and around the world to Figure 19.5—Typical diesel fuel specifications.
cut down on toxic gas emissions to minimize the damage to
the environment we all live in. The biggest changes in the
fuels specifications are the elimination of lead and methyl teristics not inherent in the fuel. They are typically derived
tertiary butyl ether (MTBE) and reduction in sulfur con- from petroleum-based raw materials and their function and
tents and toxic emissions around the world. chemistry are highly specialized. They produce the desired
The discussion and the history of the evolutions and effect at the parts-per-million concentration range (1 ppm is
current specifications around the world is a chapter in 0.0001 mass percent or 1 mg/kg). The following subsections
itself. In this chapter we will discuss major fuel properties describe the classifications of fuel additives.
and their typical specifications.
19.2.4.1 Gasoline Additives
• Oxidation inhibitors (antioxidants are aromatic amines
19.2.3.1 Gasoline Fuel and hindered phenols): Prevent formation of gums by
Figure 19.4 shows the typical minimum/maximum range of stopping gasoline’s reaction with oxygen.
specifications for gasoline fuels. • Corrosion inhibitors (carboxylic acids and carboxylates):
Prevent corrosion of tanks and pipelines by water.
19.2.3.2 Diesel Fuel • Metal deactivators (chelating agents): Prevent active
Figure 19.5 shows the typical minimum/maximum range of metal ions from catalyzing gasoline oxidation.
specifications for diesel fuels. • Demulsifiers: Polyglycol derivatives that prevent gaso-
line water emulsion in the high shear field of a cen-
19.2.4 Fuel Additives trifugal pump.
Additives are soluble chemicals mixed with fuel to enhance • Antiknock compounds: Tetraethyl lead or methylcyclo-
certain performance characteristics or to provide charac- pentadienyl manganese tricarbonyl no longer used.
• Deposit-control additives: Protect carburetor and fuel-
injection system.
Specification Unit Minimum Maximum Range • Anti-icing additives: Used to avoid icing on aircraft
RON X 83-98 exteriors.
MON x 76-85 • Dyes: Used to distinguish product grades.
(MON+RON)/2, min Calculated 84-96 • Markers: Added to gasoline to track its movement
3
Density @ 15°C kg/m 710-780 through the supply chain.
Reid Vapor Pressure @ 37.8°C kPa x 35-100 • Drag reducers: Reduce the pumping cost.
IBP °C x
T10 °C x 50-70
T50 °C x x 70-120
19.2.4.2 Diesel Additives
T90 °C x x 150-190 • Cold-flow improver: This additive lowers the CFPP and
FBP °C x 190-225 pour point temperatures to avoid blocking filters. The
Drivability Index Calculated 20-50 additive has a lower wax content similar to heating oil
E70 % vol and similar products and works by changing the size
E100 % vol
and shape of wax crystals. Cold-flow improvers do not
E150 % vol Specified only in few countries
E180 % vol
change the cloud point.
E300 % vol • Detergents: Keep fuel injectors clean.
Lead g/l x 0-0.0026 • Cetane improver: Improves cold temperature and idling
Sulfur ppm x 10-1000 of engines and boosts the cetane nonlinearly higher
Phosphorous g/l x 0-0.0004 for low-cetane diesel fuels and lower for higher-cetane-
Benzene % vol x 0-3.5
number diesel fuels.
Aromatics % vol x 25-60
Olefins % vol x 10-45
• Thermal stability improver: Improves the fuel’s resis-
Oxygen % vol x 0-3.5 tance to form particles as it circulates from tank to
engine and back again. Such particles clog filters and
Figure 19.4—Typical gasoline specifications. injectors.
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Chapter 19 n Fuel Blending Technology and Management 477

• Lubricity improver: Low-sulfur fuel has less lubricity or where:

lubricating property and absorbs water more readily, vi = volumetric fraction of component i, and
and water is an abrasive. Untreated fuel often causes n = number of components in the mixture.
excessive wear on fuel pumps and injector tips. The exponential factor is very specific to each refinery
and component type and is usually obtained by nonlinear
19.3 Blend Models regression of historical blend data.
19.3.1 Linear Blend Models
Let us assume that we want to blend three components, X1, 19.3.2.2 Type 2 Nonlinear Blend Models
X2, and X3, with qualities Q1, Q2, and Q3 to make a product This type of model is a further extension of the type 1 model.
of quality QB. A simple mathematical equation will deter- It depends on the range of the same quality of other com-
mine the quality of the final blend. ponents present in the blend before its transformation into
a linearized index. Cloud, flash, and freeze points are exam-
QB = X1 * Q1 + X2 * Q2 + X3 * Q3 (19.1) ples of type 2 nonlinear models and are illustrated below
for cloud point blending calculations as published by Ethyl
Corporation in 1981 [2]. Cloud point is predicted using a
Because the qualities (Qi) of the components are known, scaling algorithm to prevent the generation of index values
one can use a simple calculator or Excel spreadsheet to esti- that would be otherwise difficult to manage by the solver.
mate the recipe fraction (Xi) of the components to produce
the specified quality of the blend product. This is called the  MinQuality + 273 MaxQuality + 273 
linear blend model and can be safely used for fuel quali-
Scale = 
 0.5x
+
0.5x  ( 0.5) (19.4)
ties such as API gravity, sulfur, aromatics, olefins, benzene, where:
bromine number, oxygen, etc. The recipe fraction (Xi) can MinQuality is the lowest quality found in the component pool,
be either volumetric or weight depending on the property. MaxQuality is the highest quality found in the component
However, equation 19.1 cannot be used for other qualities pool, and X is the user-supplied exponent from the nonlin-
such as octane numbers (RON/MON), RVP, distillation ear regression of the refinery data.
points, pour point, flash point, freeze points, cloud point,
A blending index for each stock (IDXi) is calculated from
cetane number, CFPP, etc., for the following reasons:
component and heel quality values. The user defines the
• Qualities are highly nonlinear in nature and do not pro-
exponent (x), which is obtained by the nonlinear regression
duce acceptable results. However, the blended qualities
of the historical blend data.
of components depend only on some nonlinear func-
(1/ x)
tion of the same quality (e.g., RVP, pour point, flash  ( Qualityi + 273) 
IDX i =   (19.5)
point, freeze point, cetane number, etc.). Scale
 
• Blended qualities of components may depend on the
same qualities of other components (e.g., pour point, Next, index values are combined volumetrically to yield a
flash point, freeze point, etc.). predicted indexed quality value for the blend (IDXB).
• Components are highly interactive; that is, their effec- n

tive qualities in the blend change and depend on the IDX B = ∑ vi IDX i (19.6)
i =1
same and other qualities of other components pres-
ent in the blend. For example, octane numbers (RON/ Finally, this value is transformed back to yield a predicted
MON) depend on the olefin, aromatic, and benzene quality value of the blend.
contents of all of the other components in the pool.
QualityB = ( IDX B ) ( Scale) – 273
x
(19.7)
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

19.3.2 Nonlinear Blend Models Please note that the temperature value for the flash, cloud,
19.3.2.1 Type 1 Nonlinear Blend Models and freeze points used in the above type 2 blend models is
This type of model linearizes the component qualities using in degrees Celsius. If degrees Fahrenheit are desired as the
an index method. The indexed quality then can be blended temperature units, then replace the factor 273 by 460 for
linearly using equation 19.1 and converted back to quality their conversion to the absolute temperature units.
by using reverse transformation. An example of this is RVP, Another example of a type 2 blending model is the
as shown in equation 19.2. calculation of the ASTM D86 distillation points by the ethyl
equation [2]:
RVPIi = RVPi x (19.2) n
D86 XB = ∑ vi BVxi (19.8)
i =1
Component and heel RVP values, along with the product
specifications, are first transformed to blending indices where:
(RVPi) using a user-supplied exponential factor (x) obtained D86XB = predicted temperature at a given point X,
by nonlinear regression of historical refinery blend data. BVxi = temperature blending value of component, i, at a
The component and heel indices are blended volumetrically desired point X, calculated based on the Ethyl S-curve model:
and then transformed back to yield a predicted RVP for the
blend: BVxi = C 0 x + C1x Ai + C 2 x Ai2 + C 3 x Ai3 + C 4 x Ai Gi
1 Gi G
n x + C5x + C 6 x i2 + C 7 x Gi (19.9)
RVPB = ∑ vi RVPIi  (19.3) Ai Ai
 i =1 
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478 Petroleum Refining and Natural Gas Processing

where C = 0.003932, and

Ai = the average boiling point (based on the selected VABP D = 0.006761.
method) of component i (°F or C), In equation 19.13, the RON of the blended product
Gi = component i ASTM severity (T90–T10) (°F or C), and depends nonlinearly on the RON and the olefin and satu-
C0x–C7x = coefficients for each included D86 distillation rates contents of the components in the pool. The constants
point that are regressed from the historical blend data to A, B, C, and D depend on the types of product grades (e.g.,
customize for a specific refinery. regular, midgrade, and premium), are given by Ethyl Cor-
The volumetric average boiling point (VABP) is calcu- poration [2], and can be used with a bias term in equation
lated by the ASTM or Texaco method as follows: 19.13 to customize for a specific refinery. Alternatively, the
constants can also be obtained by regression of historical
T10 + 2 ( T 50 ) + T 90
ASTM: VABPB = (19.10) blend data for the same type of blend grades.
4 Similar and more complex equations involving addi-
tional aromatic contents of the components in the pool
T10 + T 30 + T 50 + T 70 + T 90
Texaco: VABPB = (19.11) also exist in the literature and are developed by individual
5 refineries and used in their blending system. However, it is
outside of the scope of this chapter to discuss in detail all
19.3.2.3 Type 3 Nonlinear Models existing nonlinear blend models for the gasoline octane.
This type of model is the most complex and does not fall There are also other variations of the blend nonlinear
into the above categories because the models are highly models that do not fall in any of the above three types
interactive in nature, dependent on other qualities of the because they are in the form of dependency of the final
components in the pool, and are very difficult to solve by blend qualities. Examples are illustrated as follows:
ordinary methods such as a calculator or simple Excel cal- • Volatility index
culations.
The generalized equation of this type of nonlinear VLIB = 114.6 – 4.1( RVPB ) + 0.2 ( T10 B ) + 0.17 ( T 50 B ) (19.14)
model consists of two parts: a linear term and a nonlinear
• Reformulated gasoline equations
term to represent the interaction between components and
their qualities in the pool, as shown in equation 19.12. TOX= ~ a + b * O2 + c * S + d * RVP + e * E200
+ f * E300 + g * Ar + h * Ole + i * Bz (19.15)
Qb,1 = X1 * Q1,1 + X2 * Q2,1 + X3 * Q3,1
+ ………Xn * Qm,n + f(X1,X2,X3,,…..Xn, NOX = ~ j + k * O2 + l * S + m * RVP + n * E200
Q1,1,Q1,2, Q1,n,…….Qm,1,Qm,2, Qm,n) (19.12) + o * E300 + p * Ar + q * Ole + r * Bz (19.16)

The entire effort in the design and implementation of a VOC= ~ s + t * O2 + u * S + v * RVP + w * E200
blending system centers around how to best estimate the + x * E300 + y * Ar + z * Ole + aa * Bz (19.17)
second nonlinear term, a nonlinear function of the compo-
nent mixture and its qualities, in equation 19.12 because Please note that the equations 19.1–19.17 mentioned in this
it depends on the specific refinery and its component pool chapter are only for illustration purposes and should not be
mixture for fuel blending. We will later discuss various taken as absolute correlations; hence, they should be used
methods to estimate this nonlinear term to use in the blend- with caution for your refinery only after consultation with
ing equations. a blending consultant.
An example of the type 3 blending model is the octane
numbers (RON/MON) and is illustrated in equation 19.13 19.3.3 Effects of Nonlinearity on Blend Quality
for RON: The effects of nonlinearity due to interaction of components
are illustrated in the penalization and bonus of the blend
n octane using a two-component system. Let us examine the
RON B = ∑ vi RONi effect of blending fluid catalytic cracking (FCC) (RON = 91)
i =1
and reformate (RON = 94) by mixing them in varying pro-
n  n n
 portions as shown in Figure 19.6. In this example, the blend
+ A ∑ vi RONi 2 –  ∑ vi RONi * ∑ vi RONi 
 i =1  i =1 i =1  octane is penalized between 0.10 and 0.30 RON depending
on the composition of the mixture.
n  n n
 
+ B ∑ vi Olefi 2 –  ∑ vi Olefi * ∑ vi Olefi  On the other hand, if we examine a mixture of FCC
 i =1  i =1 i =1  (RON = 91) and isopentane (RON = 90), we observe an
(19.13)
2 octane bonus of 0.10–1.6 RON, again depending on the
 n  n n
   mixture composition (Figure 19.7).
+C  ∑ vi Sati 2 –  ∑ vi Sati * ∑ vi Sati  
  i =1  i =1 i =1   We will discuss later how to estimate the octane bonus
or penalty for any combination of components in the blend
n  n n

+ D ∑ vi ( RONi * Olefi ) –  ∑ vi RONi * ∑ vi Olefi  component pool.
 i =1  i =1 i =1 
19.3.4 Methods to Handle Blend Nonlinearity
where constants A, B, C, and D are given by Ethyl Corpora- We discussed earlier that nonlinearity of the components
tion [2] as can severely affect the blend octane for gasoline blends
A = 0.003361, and must be properly accounted for to minimize the effect
B = 0.001138, --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`--- on the refinery bottom line. In this section, we will discuss
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Chapter 19 n Fuel Blending Technology and Management 479

19.3.4.2 Blending Values (Index)

In this approach, the component qualities are replaced by
blending values of indexes to account for the nonlinearity
and component interaction to simulate type 2 blend model
non-linearity. This is shown in equation 19.19:

Qb, j = ∑
n
X i BVi , j ± Bj (19.19)
i =1

where:
BVi,j = blend values (index) of component i for quality j and
Bj = average bias for quality j and is a function of product
grade.
The blending values are again nonlinear and must
be calculated by representative equation 19.20 for octane
(RON).
BlendBVj = RON j

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
2
 n

+ A  Aromj – ∑ vi Aromi 
Figure 19.6—Penalty of octane for FCC + reformate blend.  i =1 
2
 n

various methods and their pros and cons to effectively + B  Olef j – ∑ vi Olefi 
 i =1 
tackle the blend nonlinearity. The nonlinearity of the fuel
 n
 n

blends can be handled by the following methods. + C  RON j – ∑ vi RONi  ( RON j – MON j ) – ∑ vi RM∆ i 
 i =1  i =1 
19.3.4.1 Lumped Bias  n
 n

This method introduces a bias term to the linear calculation + D  Aromj – ∑ vi Aromi   Olef j – ∑ vi Olefi 
of blend quality as follows:  i =1  i =1 
(19.20)
n
Qb,j = ∑ xi qi,j ± Bj for j = 1… n (19.18) where A, B, C, and D are given in equation 19.20 or can be
i =1
regressed constants for the specific refinery from historical
The advantages of this approach are that it is simple blend data, and
and easily calculated using a calculator or an Excel spread- RM∆ i = difference between RON and MON.
sheet. It is valid for simpler and nearly linear qualities. This approach is closer to reality with the same com-
However, the bias term Bj is not constant and varies with plexity as the original equation 19.13. However, equation
product grade and component mixture, which makes it 19.20 makes it easier to program and calculate in linear
difficult to maintain a database of the bias term for a wide programs or an Excel spreadsheet, but the blend values
spectrum of blend composition and qualities. Figure 19.8 again depend on the pool composition. Because the blend
shows typical ranges of blend model bias for gasoline nonlinearity is taken care of in the blending values, the
blends for 1 month of blends and marks the variation bias term in equation 19.19 is not as variable as the one in
between blend batches and blend grades due to severe equation 19.18.
blend nonlinearity and interactions.
19.3.4.3 DuPont Interaction Coefficients
FCC +Isopentane Ble nd In this method, the nonlinear term in equation 19.13 is
92.6 replaced by a binary interaction coefficient originally devel-
92.4 oped by DuPont Corporation in 1981 as follows:
92.2 n n
92
n ∑∑ b x ij j
91.8
Qb, j = ∑ xi qi , j + i =1 i =1
(19.21)
91.6 2
Blend Octane

i =1
91.4
Linear Blending
91.2 for all i and j, where i ≠ j and bij = bji
Non-Linear Blending
91 This approach is easy to program and calculated in an
90.8 Excel spreadsheet because it is noniterative. The interac-
90.6 tion coefficients bij and bji are independent of blend compo-
90.4 sition. However, they must be determined separately using
90.2 the 50/50% mixture method.
90
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
19.3.4.3.1 50%/50% Mixture Method
% of Re for m ate
1. Collect a minimum of 5 gal of each stock.
Figure 19.7—Bonus of blend octane for FCC+ isopentane. 2. Measure the RON/MON of each component in the
Source: Reproduced with permission from [1]. laboratory.
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480 Petroleum Refining and Natural Gas Processing

BENZENE
E_V200F

E_V300F
GradeID

OXATE

AROM
E_P10

E_P30

E_P50

E_P90
MON0

GRAV
RON0

OLEF
SULF
E_EP
RDOI

RVP

VLI
No

4 C387D-1 -0.67 -0.46 -0.57 -0.35 5.1 6.23 2.63 13.8 -2.8 -40.1 -3 -6.36 18.95 -0.74 -0.02 14.53 0.48 0.007
8 C387D-1 -0.32 -0.36 -0.34 -0.05 0.73 2.83 -2.54 0.6 -1.3 -44.5 -0.1 -1.49 -0.01 -0.71 -0.17 11.51 -3.73 0.014
11 C387D-1 -0.88 -0.6 -0.74 -0.05 -0.52 -1.2 -3.81 -1.4 -0.5 -30.5 0.82 -2.45 0.035 -0.6 -0.11 14.36 -3.67 0.003
13 C387D-1 -0.57 -0.21 -0.39 -0.23 1.25 2.07 -0.95 0.88 -4.1 -38.4 -0.1 -2.15 0.025 -0.68 -0.11 14.01 -3.75 0.013
15 C387D-1 -0.31 -0.54 -0.43 -0.09 -0.57 -3.7 0.18 0.21 -0.6 -40.4 0.03 -3.19 0.03 -1.54 0.01 17.28 -2.22 0.004
22 C387D-1 -1.81 -0.98 -1.4 -0.56 5.35 0.33 7.22 17.2 9.43 -27.7 -4.6 -6.45 0.045 -1.03 -0.31 15.63 -4.61 0.02
CREG -0.76 -0.53 -0.65 -0.22 1.89 1.09 0.455 5.21 0.04 -36.9 -1.1 -3.68 0.025 -0.88 -0.12 14.5533 -2.92 0.01

25 C393C-1 0.2 -1.01 -0.41 -0.58 2.03 -4.3 -8.17 3.68 2.05 -19.1 0.53 -0.13 -0.02 -2.7 0.1 13.62 -6.59 0.028
26 C393C-1 -0.69 -0.85 -0.77 -0.57 0.98 -10 -9.84 5.06 8.3 -7.17 -1.6 -1.65 -0.01 -0.95 0.17 9.63 -10.9 0.051
27 C393C-1 -0.07 -0.51 -0.29 -0.39 -0.38 -9.1 -10.2 0.42 0.91 -16.5 -0.2 1.75 -0.01 -0.7 0.05 9.32 -12.2 0.061
28 C393C-1 0.57 -0.33 0.12 -0.47 2.69 -0.4 0.67 7.54 3.63 -13.7 -4.8 0.3 2E-06 -0.74 0.06 12.5 -10.4 0.056
29 C393C-1 -0.83 -1.4 -1.11 -0.28 0.64 -8.9 -10.6 5.88 9.49 -2.72 -1.7 -2.32 -0.02 -3.05 0.13 10.24 -8.85 0.051
CPRM -0.164 -0.82 -0.49 -0.46 1.192 -6.5 -7.62 4.52 4.88 -11.9 -1.6 -0.41 -0.012 -1.63 0.102 11.062 -9.79 0.05

32 R387D-1 -0.04 0.1 0.03 0.06 -2.65 0.17 -4.14 -13 -6.3 -33.2 6.52 1.93 -0.05 -0.04 -0.12 3.08 7.05 0.03
33 R387D-1 -0.12 -0.23 -0.18 -0.07 -2.57 -2.6 -5.5 -14 -7.3 -40.1 6.57 2.62 -0.04 0.36 -0.08 1.31 5.68 0.021
34 R387D-1 -0.45 -0.33 -0.39 0.08 -3.98 -2.6 -7.02 -17 -11 -36.5 8.25 2.67 -0.04 0.4 -0.1 1.29 5.86 0.03
35 R387D-1 -0.4 0.11 -0.14 0.16 -2.78 0.62 -6.85 -15 -4.2 -33.7 6.46 1.31 -0.04 0.2 0 2.72 8.07 0.03
36 R387D-1 -0.62 -0.33 -0.48 0.18 -3.71 -1.6 -8.08 -15 -3.7 -36.1 6.68 1.47 -0.04 0.23 -0.08 2.23 8.38 0.024
37 R387D-1 -1.05 -1.19 -1.12 0.82 -4.37 -8.3 -5.94 5.55 3.13 -45.5 -1.8 -3.26 -0.017 -2.04 0.53 10.5 -2.64 0.013
38 R387D-1 -0.73 0.19 -0.27 0.03 -2.3 -1 -5.16 -14 -3.8 -36 5.77 1.44 -0.04 0.04 -0.02 3.24 7.82 0.024
39 R387D-1 -1.31 -0.99 -1.15 0.18 -2.4 0.63 -6.27 -12 -1.1 -22.8 4.72 1.58 -0.05 0.35 -0.14 1.77 7.49 0.025
40 R387D-1 -0.82 -0.32 -0.57 0.18 -4.09 -2.7 -9.48 -19 -4.4 -31.4 7.69 2 -0.07 -0.02 0.02 3.34 9.79 0.036
41 R387D-1 0.62 0.9 0.76 0.31 -7.09 -3.7 -12.9 -27 -11 170.2 -12 -68.9 -0.04 0.02 0.06 4.75 9.63 0.024
42 R387D-1 0.57 0.89 0.73 0.08 -6.09 -3.7 -12.9 -28 -7.7 81.24 2.46 -24 -0.04 0.19 0.01 3.51 8.79 0.022
43 R387D-1 0.84 0.84 0.84 0.01 -5.09 -3 -11.7 -25 -7.4 429.6 -12 10.5 -0.05 0.14 -0.06 2.68 7.89 0.024
45 R387D-1 0.5 0.2 0.35 0.05 -5.09 -3 -11.7 -25 -7.4 153.7 -12 -70.7 -0.04 -0.11 -0.03 3.38 8.49 0.024
46 R387D-1 0.83 0.12 0.48 0.07 -5.09 -2.1 -10.7 -25 -14 425 -11 13.7 -0.04 -0.15 0.08 1.29 4.08 0.028
RREG -0.15571 -0 -0.08 0.153 -4.09 -2.3 -8.45 -17 -6.1 67.46 0.57 -9.11 -0.043 -0.03 0.005 3.22071 6.884 0.025

47 R393C-1 -0.26 -0.4 -0.33 0.26 -3.16 -2 -6.67 -13 -3.1 -22.6 5.07 5.23 -0.03 0.19 -0.02 4.28 -1.7 0.036
49 R393C-1 -0.39 0.01 -0.19 0.56 -5.18 -3.3 -11.6 -16 -7.1 -27.3 6.25 6.34 -0.03 0.3 0.04 4.38 -1.37 0.026
50 R393C-1 0.2 -0.43 -0.12 0.63 -5.35 -3.5 -11.9 -14 -3.9 -24.9 5.81 5.05 -0.03 -0.89 0 10.65 -5.79 0.032
RPRM -0.15 -0.27 -0.21 0.483 -4.56 -2.9 -10 -14 -4.7 -24.9 5.71 5.54 -0.03 -0.13 0.007 6.43667 -2.95 0.031

Figure 19.8—Example of blending model bias variation for 1 month of blends. Source: Reproduced with permission from [1].

3. Make a 50/50% mixture of all pairs of components. For all pairs of the component. The values in the figure can be
example, for six-component blends, there should be 15 simply calculated in an Excel spreadsheet using equation
such pairs at one set of process conditions and they 19.22.
must be made so as to cover all component quality vari- Equation 19.21 can be further extended to include a
ations for at least the high and low ranges of process bias term to account for other inaccuracies (discussed in
conditions. For each pair of components, there would Section 19.3.4.1).
be three RON measurements by laboratory analysis—
in total 42 (6+15 RON, 6+15 MON) measurements for 19.3.4.4 Spectrum-Based Blending Indices
both RON and MON at one process condition. Blending indices for gasoline and diesel blending can also be
4. Measure the RON/MON of each mixture by the same computed by using their near-infrared (NIR) spectrum [3].
means as the component octane. The method uses the entire spectrum of a sample rather
5. Calculate the interaction coefficient as follows: than its individual properties as in conventional index
calculation methods. Although this method offers more
Qj − 0.50 * ( q1, j + q2, j ) accurate results and faster availability of index calculations,
B12, j = (19.22)
0.25 it requires complex and proprietary spectrum blending
models, a huge spectrum database, and an extensive set of
6. The interaction coefficients are not constant and samples to build the database. The advantages are that this
depend on process changes. Hence, they cannot be method can be used for all fuel blending (e.g., gasoline, die-
trusted for all blends. sel, biodiesel, ethanol blending, etc.). The detailed discus-
7. Typically, blend components are collected over 3 sion of this method is outside of the scope of this chapter,
month’s period to represent all process conditions. and the reader should refer to the paper by Lambert in the
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

There will be 420 RON/MON measurements for just 10 www.eptq.com online journal [3].
process conditions and it is not enough at times.
8. It is very expensive and time-consuming to analyze
19.3.5 Control Matrix of Qualities
component and blend mixture octane of 500+ samples
We discussed in earlier sections that blend nonlinearity
and update the coefficients; most refineries do so only
in the blend model arises from the fact that blend qual-
once approximately every 5 years.
ity not only depends on the component composition and
their qualities but also on their interaction with other
19.3.4.3.2 Example of Interaction Coefficient Values components in the pool. Figure 19.11 shows the qual-
Figure 19.9 shows the typical set of analyzed values of ity dependence of qualities for the gasoline blends, and
RON by laboratory analysis, and Figure 19.10 shows the their relationships are reflected in the blend nonlinear
calculated values of the DuPont interaction coefficient for models.
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Chapter 19 n Fuel Blending Technology and Management 481

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 19.9—Typical octane values of blend components. Source: Reproduced with permission from [1].

Figure 19.10—Calculated DuPont interaction coefficients from values in Figure 19.9. Source: Reproduced with permission from [1].

Figure 19.11—Quality dependence matrix for components and blends. Source: Reproduced with permission from [1].
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482 Petroleum Refining and Natural Gas Processing

19.4 Recipe Optimization nonlinearity to make the equations easier to handle. The
The economic objectives of fuel blending operations are transformed equations are as follows:
• Blends should be on specifications with minimal qual-
ity giveaway and should have no violations in any Qsb,RON = x1 * qv1,RON + x2 * qv2,RON + x3* qv3,RON
circumstances. + φ1 – Gb,RON + Vb,RON (19.27)
• Reblends should be minimal for off-spec blends.
• Blends should be produced with minimal cost.
This section examines the methodology to achieve the Qsb,RVP = x1 * qv1,RVP + x2 * qv2,RVP + x3 * qv3,RVP
above blending objectives. + φ2 + Gb,RVP – Vb,RVP (19.28)

19.4.1 Control and Manipulated Blend Qsb,50% = x1 * qv1,50% + x2 * qv2,50% + x3 * qv3,50%

Variables + φ3 + Gb,50% – Vb,50% (19.29)
Let us re-examine the generalized blend equation as fol-
lows: where:
qvi,j = blend values for component i and quality j,
Qb = ∑ i =1 X i K i fi ( X1 , X 2 X 3 … X n , Q1 , Q2 , Q3 …….Qn ) (19.23)
s n
Gb,j = giveaway slack variable for quality j, and
Vb,j = violation slack variable for quality j.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
where: Now we have three equations and nine unknowns (X1,
X2, and X3 plus giveaway and violation slack variables).
K = 1 if blended by volume, Equations 19.27–19.29 have multiple possible solutions as
i
1 follows, and we must define an additional criterion to select
otherwise of component if blended by weight, and
Density  
Qsj = ∑ X i1 * K i * fi ( X i1 ,……., X n1 , Qij ,…….Qnj ..) ,
Qs = Blended Specification.  i 
b
 
∑ X i2 * K i * f j ( X i2 ,……., X n2 , Qij ,…….Qnj ..) ,
In the above equation Xi are the manipulated variables  i 
because they are changed or manipulated to achieve the  
target blend specification, Q sb (controlled variable). If the ∑ X im * K i * f j ( X im ,……., X nm , Qij ,…….Qnj ..) (19.30)
blend is a three-component system, then it can be solved  i 
deterministically for three qualities. However, in reality,
a blending system has more unknown variables than the 19.4.3 Objective Function
known variables and hence it cannot generate an unique We introduce an additional criterion in equation 19.30 to
solution. We will next discuss how to solve equations select a feasible solution subject to minimal quality give-
with more controlled variables (qualities + slack) than the away from specifications or maximal blend profit. The
manipulated variables (composition). condition is stated as

 
19.4.2 Slack Variables Qsj = Optimum ∑ X i1 * K i * f j ( X i1 ,……., X n1 , Qij ,…….Qnj ..)
Let us examine a three-component blending system to con-  i 
trol three blend qualities (RON, RVP, and 50% distillation (19.31)

( )
point) with minimum and maximum specifications using
subject to maximal profit on blend P b – ∑ i =1 X i * Ci or mini-
n
nonlinear blending equations with DuPont coefficients.
• Minimum specifications mal quality giveaway ( Qsj – Qbj ) , where Pb is the sale price of
the blend product and Ci is the cost of component i.
Qsb,RON < x1*q1,RON + x2*q2,RON + x3*q3,RON Now, the monetary cost of a component is not easy to
+ β12*x1*x2 + β13*x1*x3 + β23*x2*x3 + φ1 (19.24) compute in a refinery and is practically not used. Instead, a
blending value is computed for components on the basis of
• Maximum specifications their RON and RVP values relative to the blend product. It
is outside of the scope of this chapter to discuss the meth-
Qsb,RVP > x1*q1,RVP + x2*q2,RVP + x3*q3,RVP odology and equations to calculate component blending
+ β12*x1*x2 + β13*x1*x3 + β23*x2*x3 + φ2 (19.25) values for the cost of components.
The above objective function is a simpler form of the
• Maximum specifications basic terms of optimization. In reality, there are other fac-
tors considered in a refining blending system to optimize
Qsb,50% > x1*q1,50% + x2*q2,50% + x3*q3,50% + β12*x1*x2
the recipe. An example of additional terms used in the for-
+ β13*x1*x3 + β23*x2*x3 + φ3 (19.26) mation of an objective function is shown in Figure 19.12.
The objective function would then be as follows:
where:
φ1, φ2, φ3 = model biases. bjective function = A –B + C – D –E –F – G – H – I – J
O
Now, equations 19.24–19.26 cannot be solved uniquely (19.32)
because of inequalities in the equation. Hence, we will
introduce slack variables in the above equations to convert Figure 19.12 explains the definitions of each of the
them to equalities and also use the blending values for terms listed in equation 19.32.
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Chapter 19 n Fuel Blending Technology and Management 483

Applicable for the

optimization of
Term Description Maximum Minimum
Profit Giveaway
A Values of Products Yes Yes
B Cost of all Stocks Yes
C Value of Closing Stock Inventory Yes
D Cost of Antiknock Compound Yes
E Cost of Cetane Improver ** Yes
F Cost of Distress Buying Yes Yes
G Cost or Value of Distress Selling Yes Yes
H Cost of Distress Quality Buying or Selling Yes Yes
I Penalty Cost for Deviation from Preferred Recipe Yes Yes
J Quality Giveaway Cost and Violation Penalty Cost Yes
** For distillate blending only

Figure 19.12—Additional terms in the objective function. Source: Reproduced with permission from [1].

Distress buying and selling costs are used to buy or sell Nonlinear blend equations can be solved by successive
components to ease the infeasible solution due to shortage linear programming (SLP) or a true nonlinear solver. How-
or excess of component inventories. Typically, the distress ever, SLP is a sampler technique because it involves iteratively
buying cost is higher than the component cost (or blending executing the linear programming (LP) algorithm until the
value cost) and the selling cost is less than the component solution converges, but it requires custom programming over
cost (or blending value cost) to facilitate arriving at an the commercial LP algorithm. The implementation of SLP in
optimal blend recipe solution. The objective function in commercial LP programs usually requires interface to it, if
Figure 19.12 has typical cost factors and can be modified feasible and tools are available from the vendor, or it creates
to include other expensive additives. The violation penalty a wrapper around the algorithm to repeatedly solve the LP
costs are usually higher by many-fold and are used in the matrix until the nonlinear qualities and blend recipe converge.
relative importance of quality violation. For example, RON
cannot be violated and hence may be given a violation pen- 19.5 Design of a Typical Blending System
alty factor of 10,000 with a penalty factor of 8,000 for RVP In this section we will discuss design considerations for a
and so on and so forth. Typically, offline optimization by a typical blending system and will focus mostly on a gasoline
planner or blend engineer is done based on profit whereas blender because it is the most complex blender in a refin-
online optimization focuses on the minimization of quality ery [4,5]. A typical blending system has the following ten
giveaways. Since the cost of components are not accurately automation islands, in addition to design configuration of
available, their relative blending values are used in the blending configuration:
profit function. 1. Tank farm
2. Automatic tank gaging system
19.4.4 Optimization Algorithms 3. Laboratory analysis
The system of equations discussed in earlier sections can 4. Field equipment and instrumentation
be solved by any of the three mathematical techniques on 5. Fuel additives
the basis of the nature of the blend equations used. Figure 6. Quality analysis and measurements
19.13 shows a summary of blend equations and mathemati- 7. Advanced blend control, optimization, planning, and
cal techniques. scheduling

Figure 19.13—Mathematical techniques used for blend equation. Source: Reproduced with permission from [1].
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Copyright ASTM International

AST-MNL58-11-0801-019.indd 483 3/12/13 2:52 PM

484 Petroleum Refining and Natural Gas Processing

Automatic
8
Offline Blend Optimizer &
10
2 Tank Gauging Distributed Control
System (DCS)
Scheduling System
Online Blend Control & End Product
System 7 Advanced
Control System
Optimization
Dispatch
Regulatory Blend Control

Online Analyzers &

Sampling System
Tanks

Product
B
L Tankers

Stocks
M E
N
M M M
M

M
S

D
M

M M

4
M M

E
M

1 Tank Farm
Field Equipment / R
Pipelines

Instrumentation
S
K Trucks
I
Total Blend Flow
, M3
Blend Target Rate, M3/Hr
8000
2000
BLEND
HEADER
TV-124

Heel, M3
Volume, M3
1000
9000
Maximum, M3 12000
9 D
LEAD ED

ADDITIVES CONCENTRATIONS
UN LEA DE D

Units Spec Current

ANILINE Aniline mg / lit 2 1.95
FI2109 Detergent mg / lit 280 275
PV 3.95 LIT/HR TEL ml / gal 1 0.956
SP 3.96 LIT/HR
M
F 13.86 LIT/HR FI2212
PV 608.7 LIT/HR

3
SDV2115D
SDV2115A
SP 608.7 LIT/HR M
2115-P F 2130.4 LITS
M M SDV2112A
SDV2115B
2113-P
SDV2115C SDV2109B
M
2115-PA
SDV2112B
LEAD

Rail
2113-PA
FI2113 FI2211
FI2210 PV 0
DETERGENT
PV 2.3266GPM
SP 2.3266GPM PV 42.326 GPM SP 0 M
F 600.58 GALS F 15000.58 GALS F 0
M SDV2111A

2114-P

Laboratory
TEL SDV2113 SDV2109A
M

Wagons
SDV2111B
DILUTANTS 2114-PA

5 Additive Control
System

Source:
Figure 19.14—Automation Training
islands of aManual - Strategic
typical blending Fuelssystem.
BlendingSource:
Technology and Management,
Reproduced with permission from [1].
Reproduced with Permission from Offsite Management Systems LLC, Sugar Land, Texas, USA

8. Computer system inventory buildup. On the other hand, run-down blending

9. Blend header requires more instrumentation, is limited in optimization
10. End-product dispatch flexibility, and is affected by process swings; it has the
Figure 19.14 shows all automation components of a advantages of low inventory buildup. A limited extent of
typical gasoline blending system, and we will discuss the optimization for inline and run-down blending to ships
design considerations for each one of them in detail in the and pipelines means that a refinery does not get a sec-
following sections. ond chance to correct the giveaway of violated products
because the product moves out quickly (pipeline) or is dif-
19.5.1 Blending Configuration ficult to access (ships).
A fuel blending system is configured in many ways,
depending on the source, destination, product type, refin- 19.5.2 Tank Farm
ery configuration, degree of complexity, and expected A blending tank farm consists of tanks for components and
flexibility to operate and optimize. Table 19.2 shows products and is configured in many ways. Blending tank
the types of blending configurations used in a typical farms offer inherent pros and cons:
refinery. • Single versus paired blend stock tanks: Each compo-
The extent of optimization is defined as the abil- nent can have a single tank, paired tanks, or a hybrid
ity and freedom to manipulate the component recipe to combination of single and paired tanks for some of the
arrive at the final product specifications. In general, inline components. The paired component tanks are the pre-
batch blending configurations are less complex and more ferred design consideration because it offers flexibility
flexible in blend optimization, but they have the disadvan- in the planning process, constant tank quality during
tages of increased tankage requirement and large product blending, and stable recipe control.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Table 19.2—Blending System Configuration

Degree of Extent of
Mode Source Destination Product Type Complexity Optimization

Inline batch Tank Tank Gasoline, diesel, fuel oils Fair Excellent

Inline batch Tank Pipeline or Ship Gasoline, diesel, fuel oil High Limited

Run-down Units Tank Diesel, kerosene, jet fuels Fair Average

Run-down Units Pipeline or Ship Diesel, kerosene, jet fuels High Limited
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Chapter 19 n Fuel Blending Technology and Management 485

Figure 19.15—Recommended stock tank configuration for a blending system. Source: Reproduced with permission from [1].

• Running versus closed stock tanks: Running stock tanks c ontinuous swapping of the stock tanks based on blend
receive feed from the units while they feed the blending recipe and thus causes a loss of production, quality
system. This mode of operation continuously changes degradation, and less optimal final blend quality. This
the quality of the stock tank and thus affects the blend can be avoided by using stream pooling as discussed
control and optimization downstream of the stock above to rebalance the stock tanks versus control loops.
tank. On the other hand, closed stock tanks do not Figure 19.15 shows the recommended design consider-
receive the feed while blending and hence their quali- ations for configuring stock tanks and pooling of wild and
ties do not change, remaining the same as those used in low-quality streams.
the blend planning of the blend recipe, thus minimiz- It is absolutely necessary to install an automatic tank
ing the effect on the blend control system. gaging system (ATGS) for all blend stock and product tanks
• Stream pooling and wild flows: Some refineries have to monitor the tank inventory in real time for the blending
multiple streams of low quality, a wild stream from system. Because this topic is dealt with in great detail in
external sources, or both. If these streams are fed Chapter 20 on tank farm management, it will not be dis-
directly to the blender, the blend control is erratic and cussed in this chapter to avoid duplication.
surely ends up in huge quality giveaway or reblends.
Hence, it is a good design practice to pool all of these 19.5.3 Field Equipment and Instrumentation
wild and low-quality streams into an existing stock It is very important at the design stage of a new blending
tank with components of comparable qualities. The system that appropriate instrumentation is provided for a
stream pooling has a risk of quality stratification fully automatic blending operation. This fact is sometimes
if the component qualities are quite different. The ignored by the refineries to minimize the cost of the blend-
best possible way to avoid quality stratification is to ing system by not allocating adequate funds for the field
install a mixture in the tank to homogenize the tank equipment and instrumentation. Table 19.3 shows the
content. design recommendation of various instruments to install
• Stock tanks versus control loops: It is not uncommon for a fully automatic system.
in refineries for the number of stock tanks to be more Figure 19.16 shows the locations of all required/
than the number of control loops. This results in
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
optional instruments in a typical blending system.
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486 Petroleum Refining and Natural Gas Processing

Table 19.3—Location and Requirements of Instruments in a Blending System

Equipment Location Manual Valves Motor-Operated Valve Pressure Controller Flow Controller Flow Meter
Stock tanks Inlet Required Optional
Outlet Required
Pumps Inlet Required
Outlet Required
Control loop Required Required
Header Inlet Required
Outlet
Product tanks Inlet Required
Outlet Required

19.5.4 Quality Analysis and Measurements blend models used in the blending system also predict the
The qualities of stock and products must be known before, qualities at the header and final product qualities. Another
during, and after the completion of a blending batch in real chapter (18—“Product Analysis and Quality Control”) in
time, offline analysis, or both. The qualities in a blending this manual covers the test methods for laboratory analysis.
system are made available by any one or all of the follow-
ing methods: 19.5.4.2 Online Analysis of Stock and
• Laboratory analysis Header Qualities
• Online analyzer Blend qualities of stock tanks and the blend header are
• Model-based prediction analyzed by online analyzers using the following strategy:
• Discrete analyzers: RVP and sulfur are analyzed by dis-
19.5.4.1 Laboratory Analysis of Stock and crete analyzers in conjunction with a multiplexer and
Product Qualities multistream sampling system. Discrete analyzers mea-

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 19.17 shows the traditional methods of quality sure only one quality of one stream at a time.
estimation by laboratory analysis samples (S) for stock, • Integrated analyzers: These include spectrum-based
product tanks, header qualities, and online analyzers (A) analyzers such as NIR or nuclear magnetic resonance
after the blend header to measure blended qualities. The (NMR) to simultaneously analyze multiple qualities.

5
PRESSURE
CONTROLLER

2 2
M 7
1 T 51
-
3 3 T 12
-
V 9 M V 4
6
M M M

M
S

M
T 12
-
T 52 M M V 6
-
V 0 M M

3 M

3 4

PRESSURE
1 MANUAL VALVES 3 MOV 5 CONTROLLER 7 HEADER
FLOW
2 TANKS 4 PUMPS 6 CONTROLLER

Figure 19.16—Recommended instrumentation for an automatic blending system. Source: Reproduced with permission from [1].
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Chapter 19 n Fuel Blending Technology and Management 487

Figure 19.17—Method of quality estimation in the blending system. Source: Reproduced with permission from [1].

Qualities such as octane (RON, MON), RVP, distillation • On the other hand, integrated analyzers require extensive
points, olefins, aromatics, benzene, and many more efforts and expertise to develop NIR/NMR models for a
can be analyzed by a single integrated analyzer, thus specific refinery under a range of process conditions.
saving huge expenditures for discrete blending analyz- • The usability of integrated online analyzers is limited
ers. Chromatography or a similar technology-based because they are activated only during blend runs (10–
analyzer for multiple distillation points is another 12 h/day) and remain dormant the rest of the time. They
example of an integrated analyzer. also require 20–40 min of line-up and a sample stabiliza-
• Multiplexed sampling system: Although discrete and tion period, thus losing initial blend quality information.
integrated analyzers sample one stream at a time, their • Tank qualities are not available to the refinery planner
usability is enhanced by using a multiplexed multi- in time for recipe planning because they depend on lab-
stream sampling system. This strategy samples compo- oratory analysis. This may result in quality giveaways
nent tank exit streams and a blend header at slow and or reblends if stock tanks are running during blending.
fast pace, respectively, and sends them to the set of ana- A recent development has eliminated some of the disad-
lyzers for analysis. In this way, all streams are analyzed vantages of laboratory and online analysis by installing an
online by one set of analyzers. Stock tank exit streams external tank quality tracking system (software) and reposi-
are usually sampled at a slow frequency of 20–30 min/ tioning the online analyzers at the inlet points of the stock
stream, and a blend header in fast loop mode is sam- tanks rather than traditional tank exit points [6]. Figure 19.19
pled at a frequency of approximately 2–3 min/sample. shows the functionality of the online tank quality tracking
This is because stock tank qualities change slowly system in conjunction with alternate placement of online
compared with the blend header qualities. On the other analyzers. The advantages of this technology are
hand, blend control and optimization depend mainly • It reduces the laboratory analysis load by 40–50%
on the blend header quality in most blending systems. for blend tanks and the cost by an average of $0.5—
Figure 19.18 shows a typical blending system design 1 million/year [7].
for online analyzers and a multiplexed multistream sam- • Tank qualities are available 24 × 7 to all online/offline
pling system. applications.
• Online analyzers are a larger percentage of the time
19.5.4.3 Model-Based Tank Quality and hence give a better return on investment (ROI).
Measurement • The software contains more than 70 nonlinear quality
Quality measurements by laboratory analysis and online models and can also be used for nonblend tanks.
analysis using integrated analyzers with a multiplexed • Process units upstream of blend tanks can use this online
sampling system as described earlier have the following tank quality information for feedback control purposes.
inherent disadvantages: • It seamlessly integrates with existing and future blending
• Laboratory analyses for blend tanks are manpower- control system software from any third-party vendors.
intensive ($3–4 million/year for a 300 KB/day refinery • It has been demonstrated to save refineries $2–2.5 mil-
with 44 blend tanks), slow in turnaround period (6–8 h), lion/year to minimize quality giveaways for a run-down
and are not suitable for running stock tanks and offline/ blending system without an online control system in
online blend recipe optimization applications. place [6].
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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488 Petroleum Refining and Natural Gas Processing

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 19.18—Online analysis system with a multiplexer for a typical blending system. Source: Reproduced with permission from [1].

Figure 19.19—Model-based tank quality tracking system with strategic placement of analyzers. Source: Reproduced with
permission from [1].

19.5.5 Advanced Blend Control, Optimization, automated blending system consists of the following three
Planning, and Scheduling tiers:
In this section, we will discuss the different layers and 1. Regular blend control;
components of an advanced blend control, optimization, 2. Online blend control and optimization; and
planning, and scheduling system. A most modern and fully 3. Offsite blend optimization, planning, and scheduling.
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Chapter 19 n Fuel Blending Technology and Management 489

We will discuss in the next sections that the first level of The limitations of the regulatory blend control are
distributed control system (DCS)-based regulatory control • It cannot use feedback from analyzers to adjust the
is absolutely required for the safe operation of a blending recipe.
system, and the third level to optimize the recipe in an • It cannot handle changes in the component tank
offline mode is recommended for minimizing quality give- qualities.
away and reblends. The second level of online blend control • It can only use recipe as downloaded by the planner
is optional and may not be required at all on the basis of a and cannot adjust it to meet final specifications.
refinery’s blending configuration.
19.5.5.2 Offline Blend Optimization and
19.5.5.1 Regulatory Blend Control Planning
Almost any modern refinery of reasonable capacity The next step in blend control evolution was to implement
(>100 kb/day) has implemented a DCS- or programmable some sort of recipe optimization, initially using Excel’s
logic controller (PLC)-based regulatory blend control sys- GRG2 algorithm, and download the recipe to DCS online
tem for an inline blender. However, there are still some or manually via e-mail and phone to the blend operator
refineries in the world that practice manual sequential (one or both. The refinery planner or blend engineer in some
tank at a time) blending operations. cases would gather the last tank qualities from the labora-
The main objectives of DCS-based regulator blend con- tory and optimize the recipe on the basis of the desired
trol system are specifications and blend batch size. This was initially
• Control the initial blend recipe as downloaded by the successful for linear blend models. It was later upgraded
planner, to a more sophisticated offline optimizer by third-party
• Minimize the quality giveaways by monitoring the blend vendors incorporating nonlinear models and many other
header by a set of discrete online analyzers (RON is mea- desirable features. Figure 19.21 shows a two-tier blend
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

sured by cooperative fuel research [CFR] knock engines), system with a regulatory blend control and offline blend
• Provide blend trim control to adjust the final tank qual- optimizer.
ity for violation or excessive quality giveaways, and However, the recipe so planned and optimized is only
• Safe blending operations. good if the component tank qualities do not change dur-
A refinery normally implements many more features ing the actual blend execution. This was never the case for
in the DCS-based regulatory control system. However, it is running tanks. Hence, the planner’s initial recipe deviated
outside of the scope of this chapter to discuss all of these from the final version on the basis of how severe the com-
features here. Figure 19.20 shows a system diagram with ponent tank quality changed during blend and what kind of
online analyzers for a DCS regulatory control system. blend models were used in GRG2 or third-party software.

Recipe Planned
and Downloaded
by Planner

FT Flow Ratio DISCRETE ANALYZERS

Inventory Constraints

Setpoints
DIST RON MON RVP

FT
Heel

Product
FT Tank

Component Flow Stations

Tanks

Figure 19.20—DCS-based regulatory blend control system. Source: Reproduced with permission from [1].
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490 Petroleum Refining and Natural Gas Processing

Figure 19.21—Two-tier blending system with regulatory blend control and offline optimizer. Source: Reproduced with permission
from [1].

The combination of all of these inherent disadvantages in 19.5.5.4 Blend Planning and Scheduling
this two-tier system either resulted in quality giveaway or The blending planning process in a refinery starts from
violation. A refinery cannot sell the products with off-specs, a corporate planner and ends with a blend optimization
but they can accept the reasonable quality giveaways to sell engineer in a specific refinery. The planning period is
the product. approximately 3–6 months at the corporate level and 1–3
days at the specific refinery for blend executions. The plan-
19.5.5.3 Online Blend Control and ning process also breaks down the multiple product-grade
Optimization market forecast (A, B, C) total for 3 months in a long-range

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Because the blend stock qualities were invariably changing plan, breaks down multiple grade batches (B1, B2, B3) in
because of limited closed tanks, they were not available in a medium-range plan, and further breaks down into single
time to plan for recipe optimization. The final recipe devi- blend batches such as B11, B12, B13...B21, B22, B23, etc.,
ated from the initial planner’s recipe, which was optimized in short-range plans.
to meet the target specifications. Therefore, it is almost A refinery planner makes a plan for 15-to 30-day blend-
necessary to implement another tier of online blend control ing batches and uses a rollover scheme as shown Figure
between the regulatory blend control and offline optimizer 19.23 to move the next day’s blend recipe to the current
to solve these problems. recipe. For example, 30 days is broken into a single blend’s
However, the traditional implementation of online plan for the next 7 days, an aggregate blend batch plan for
blend control in which the online analyzers are installed the next 7 days, and then an aggregate blend production
at the tank exit did not help the planner because they had plan for the next 15 days. As the blend quality and market
to rely on the laboratory analysis of tank qualities before information become more accurate from the next day’s
recipe optimization. Also, the expensive set of integrated blend to the 30th day’s blend, the rollover process moves the
NIR/NMR analyzers is not used at all for 40–50% of the blend plan accordingly.
time.
Figure 19.22 shows the design of a blending system 19.5.6 Computer System
with a tank quality tracking system and strategic placement A blending system computer system consists of three main
of online analyzers to solve the above-mentioned problem. components: the DCS, the advanced control system, and
This design consideration takes the tank quality integration software/hardware interfaces with plant equipment/signals
function out of the online optimizer module and shifts it to and a third-party system. This is a very challenging and time-
the tank quality tracking system for consistency of blend consuming task, and their seamless integration plays a very
models throughout the blend system modules. important role in the overall success of the blending project.
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Chapter 19 n Fuel Blending Technology and Management 491

Offline Planner
Online Tanks Optimizer
Quality Tracking SULFUR ANALYZER
SAMPLING
System Online Blend Control SULFUR
SYSTEM
and Recipe Optimizer
COMPONENT HEADER &
TANKS PRODUCT
QUALITIES TANKS
QUALITIES
NIR
NIR ANALYZER
SAMPLING
SYSTEM
RVP

REGULATORY BLEND CONTROL

FT
Inventory Constraints
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Flow Ratio
FT Setpoints
Heel

Product
FT Tank

Component Flow Stations

Tanks

Figure 19.22—Recommended design of a blending system on the basis of recent developments. Source: Reproduced with
permission from [1].

1 2 3 4 5 6 7 8 9
Period 8 = 7 Days Period 9 = 17 Days

Period 8 = 7 Days Period 9 = 16 Days

Period 8 = 7 Days Period 9 = 15 Days

Period 8 = 7 Days Period 9 = 14 Days

Period 8 = 7 Days Period 9 = 13 Days

Period 8 = 7 Days Period 9 = 12 Days

EXECUTED ROLL-OVER
BLENDS PROCESS

Figure 19.23—Thirty-day blend rollover planning process. Source: Reproduced with permission from [1].
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492 Petroleum Refining and Natural Gas Processing

19.5.6.1 Distributed Control System 19.5.6.3 Interfaces

In earlier sections, we discussed that tier 1 blend control is In addition to the DCS and advanced control system, the
resident in a DCS and absolutely required for safe operation implementation of a blend system requires many interfaces
and recipe control of inline or a sequential blending system. between plant data and third-party software and databases
Although the operational philosophy of the regulator blend for challenging system integration. Examples of these
control is the same, their implementation varies from DCS required interfaces are
to DCS and must be specifically designed, developed, and • Process and systems interface with plant database and
customized for each refinery. instruments signals;
• Offline blend optimizer interfaces;
19.5.6.2 Advanced Control Computer • Tank quality tracking system interfaces;
System • Online blend control interfaces;
A blending control system is typically implemented on • Offline/online blender interfaces;
high-end PCs using client-server architecture and consists • Oil movement interfaces, including a tank farm and
of the following components in the technology set, although gaging system.
it may vary slightly from the system provider and DCS
vendor: 19.5.7 Blend Headers
• Expert system objects; A blend header is simply a piece of pipe that is connected
• Web link/ActiveX links; to all pipelines carrying the blend component streams
• Oracle/SQL server database; before feeding to the product tank. The main purpose of the
• Windows server and workstations; blender is to provide a turbulent mixing of all component
• Integrated Fortran/C/C++ modules for specific func- streams for a homogeneous mixture. A blending system can
tionality/computations; be configured either as a single blender (gasoline, diesel,
• Nonlinear optimizer, CPLEX™, Minos™; and fuel oils) or multiheaders for run-down distillate or ker-
• Nonlinear integer scheduling algorithm; osine blending. Another example of a multiheader blending
• Integrated third-party ActiveX controls; and header system is crude and naphtha blending.
• DCS/process database bridges. A blending system with a single blend header is very
Figure 19.24 shows a typical blending system client- flexible to operate and efficient to control and optimize the
server architecture. recipe. On the other hand, multiheader blending systems

NT/W
NT/W2K
/ 2K ,
G2 ,
G2, Workstation
Server
Serv
Server
Workstation
G2 Telewindows

Control
C
Con
on Planning
Pla
Scheduling
Sch
BLENDING
ENGINEER REFINERY
PLANNER
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Ethernet
t TCP/IP

`
HIGHWAY
HIGHWA
Y
DATALINK `

Distributed Communications
(DCN) Network (DCN) USERS

BLENDING
DISTRIBUTED OP
OPERATOR
CONTROL L M
MODULE
CONTROL
SYSTEM )DCS)
DCS) `
SYSTEM (DCS)
Tank Gauging
CONTRO System Computer
CONTROLLER
LLER
BLENDING
OPERATOR

FIELD EQUIPMENT
AND INSTRUMENTS

Figure 19.24—Typical system architecture for a blending system. Source: Reproduced with permission from [1].
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Chapter 19 n Fuel Blending Technology and Management 493

are difficult to operate and less flexible to control and 19.6.1 Sources of Error
optimize because the recipe of multiple products simulta- The discussion in the previous section focused on the blend
neously interacts with all available streams. A component models and illustrated that the nonlinearity in the blend-
recipe has process restrictions in a multiheader system and ing phenomenon can drastically affect the refinery bottom
cannot drastically be changed by the online optimizer. line; hence, we discussed methods to effectively handle
Design consideration for a blend header involves the nonlinearity. However, the errors in the blend predic-
length, diameter, pressure, order of components connecting tion are not limited to the nonlinearity of the blend model
points, mode of connection (vertical, horizontal or both) alone but also to additional sources of errors, as shown in
and distance between two connection points. The discus- Figure 19.25.
sion of this is outside of scope of this chapter. The sources of errors as identified in Figure 19.25 are
defined as follows:
19.5.8 End-Product Dispatch 1. Analyzer transport lag,
The blend product can be blended into a product tank, 2. Analyzer dead time lag,
tanker, ship, and bunker or directly into a pipeline. The 3. Analyzer dynamic lag,
design of a blending system is different depending on the 4. Analyzer measurement inaccuracy,
product destination. 5. Stream and tank sampling errors,

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
• Tank-to-tank blending 6. Laboratory analysis repeatability and reproducibility,
• The final product tank quality can be readjusted by 7. Inaccuracy in quality correlation,
reblending for excessive quality giveaways or viola- 8. Inaccuracy in blending method,
tions before dispatch to customers. 9. Flow measurement, and
• The online control and optimization is focused on 10. Product tank prediction bias.
the final blend tank, taking into account the blend
header quality as measured by the online analyzers. 19.6.2 Estimation of Biases
• The final product tank is recirculated for 2–4 h to The next approach would be to estimate the corrections in
make it homogeneous before its dispatch. the above sources of error, which is accomplished by defin-
• Tank-to-ship/pipeline/tanker/bunker blending ing lumped bias parameters as follows:
• The final product tank quality cannot be readjust-
ed but must be certified for meeting the specifica-
Bj = ∅l + ∅a + ∅m + ∅t (19.33)
tion. Quality giveaways must be ignored.
• The online control and optimization is focused on the
blend header quality to blend it to specification and where:
must be certified online using NIR/NMR analyzers. Bj = lumped blend quality bias,
∅l = laboratory analysis bias,
19.6 Data Reconciliation ∅a = online analyzer bias,
Data reconciliation is a methodology to rationalize the dif- ∅m = model prediction bias, and
ference between “ideal” and “real” data by minimizing or ∅t = tank quality bias.
closing the gaps between them. In this section, we will first The parameters in equation 19.33 can be estimated in
identify all sources of error in the blending system and then a systematic order by analyzing the historical data of online
discuss how to estimate those errors (or bias) for feedback analysis, the laboratory analysis of streams, and the final
corrections. tank quality and model prediction. Figure 19.26 shows the

7
j
Xi , Qi
Q
j
b = f (X k
j
, Qk ) Ppj
8 10
BLENDING HEADER PREDICTED
A jp
BLEND PROPERTIES
MODEL

1 2 1 2 j
M p MODEL BIAS
3 4 3 ANALYZER
MEASUREMENT CALCULATIONS

5 6 5 6
L jp
LABORATORY
9 MEASUREMENT

εj

BIAS FEEDBACK CORRECTION

Figure 19.25—Sources of errors in a blending system. Source: Reproduced with permission from [1].
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494 Petroleum Refining and Natural Gas Processing

Stream Sample Lab

Analysis
Lab Analysis Bias
from “Round
Robin” Tests
Φl
Stream
Online
Analyzer
Analyzer Bias Φa
Blend Predicted Blend
Components Header Quality
Online Analyzer
at Blend Header
Blend Model Bias Φm
Final Blend tank Tank
Φt
Final tank lab
Quality
analysis Prediction Bias

Final predicted
tank quality

Figure 19.26—Information flow for the calculation of various blending biases. Source: Reproduced with permission from [1].

information flow diagram for the calculation of the above 100 kbbl. The payback period for full automation and opti-
parameters. mized blending operations is approximately 12–18 months,
The analyzer as shown in Figure 19.26 is estimated by maximum. On a conservative scale, benefits from the auto-
comparing the measured online analyzer value with the mated blending system are in the range of $10–12 million/
laboratory sample analysis at the same instance. This ana- year. Figure 19.27 shows the source of these benefits for
lyzer bias along with other techniques such as using a last batch and run-down inline blending systems.
good value corrects the analyzer value online.
19.7.2 Where and How to Start
19.7 Justification and Implementation of There is no universal answer to this question because it
a Blending Project depends on the current state of the refinery’s blending sys-
In earlier sections of this chapter, we basically discussed all tem and the approach needed to reach the final state, a fully
aspects of the blending technology. In this section we will automated blending system. There are in general four states
discuss how to assess the current state of a refinery’s blend- of the refinery’s blending operation status:
ing system; how to perform data analysis for the economic 1. Negligible or few installed automation components.
justification; and, if justified, how to successfully imple- 2. Most field automation is installed but there is still
ment and manage a blending upgrade or revamp blending manual blending.
project. 3. Inline blending only and no advanced blend control.
4. Full automation but outdated offline/online advanced
19.7.1 Economical Benefits control.
Let us illustrate the economical importance of blending Figure 19.28 shows the recommended paths and durations
operations in a refinery by considering the effect of the on the basis of the current state of the plant’s blending
profit margin of blended fuels. We will consider only gaso- operations.
line fuels here for simplicity.
Let us assume that an efficient blending operation 19.7.3 Identifications and State of the
saves $0.01/gal of gasoline. For a 100-kbbl/day refinery, Automation Areas
producing 50% gasoline will save The next step in the blending project justification would
be to identify and assess the state of the automation areas
$Profits/year = 100,000 bbl/day × 42 gal/bbl in the blending operations. The author of this chapter has
× 0.50 gal gasoline/gal crude × $0.01/gal gasoline developed a proprietary methodology to assess the state of
× 365 days/year = $7.665 million (U.S.)/year the blending system in a refinery that is discussed briefly
in this section. This methodology defines the following two
Savings from blending automation and optimization indices:
is typically an average of 2–3 cents/gal of gasoline. It is 1. Automation effectiveness index: This measures the state
well documented that efficient blending operations can of field equipment, infrastructure, computer hardware
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achieve a savings of approximately $100,000 (U.S.)/batch of and software, etc., against the ideal industry standard,
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Chapter 19 n Fuel Blending Technology and Management 495

Batch Run-down
Blending Blending
• Offline Blend Optimization REQUIRED OPTIONAL

and Planning
Quality Giveaways 25-30 % 60 -70%
Recipe Optimization 55-65 % 30 -40%
Inventory Minimization 5-10 % 0%
• Online Blend Control and OPTIONAL REQUIRED
Optimization
Quality Giveaways 70-80 % 70-80 %
Recipe Optimization 10-20 % 20-30 %
Inventory Minimization 0-5% 0%

• Regulatory Blend Control REQUIRED REQUIRED

Increase in Production 10-15 %

Figure 19.27—Relative economical benefit matrix for batch and run-down inline blenders. Source: Reproduced with permission
from [1].

Refinery Blending Preliminary Feasibility Study Project

Operation State Plant Survey & Master Plan Execution

Negligible or few Conduct plant survey

Conduct full Implement all
feasibility study and recommendations of
automation by external blending
develop master plan the master plan
automation expert
installed currently document document

1-2 Days 3 Months 12-18 Months

S Most of field Conduct plant survey

Conduct full
feasibility study and
Blending
automation installed upgrade Benefits
T
by external blending
develop master plan
but manual blending automation expert Auditing
document project
and Key
A 1-2 Days 3 Months 9-10 Months Parameter
Index (KPI)
R Monitoring
In-line blending
T Blending
Conduct plant survey Conduct advanced
by external blending control and
only and no automation and optimization strategy
optimization
advanced controls optimization expert and benefits document project

1-2 Days 1 Months 3-4 Months

Conduct days plant Online control

Full automation but Online control and
survey by external optimization system
outdated offline /online blending automation upgrade strategy
optimization system
advanced controls upgrade project
and optimization expert document

1 Day 1 Week 1-2 Months

Figure 19.28—Recommended road map for an upgrade or revamp blending project. Source: Reproduced with permission
from [1].

desirable benchmarks, or both. This index is usually models; extent of quality giveaways; and reblend con-
generated by conducting a detailed plant survey of all trol, optimization, and planning activities. This index
automation components. is generated by a detailed analysis of 3–6 months of
2. Operational efficiency index: This measures how well --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
historical blend data to estimate various parameters to
the blending is executed in terms of deployed blend build this index.
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496 Petroleum Refining and Natural Gas Processing

Figure 19.29 shows a summary of these two indices for adapt “pay-as-you-go” implementation of blending automa-
a typical refinery of 300 kbbl/day. The author of this chapter tion components. In this respect, offline optimization is the
used data for an actual plant survey to analyze the data. Fig- fastest tool to implement at low cost to achieve maximal
ure 19.29 shows that there is direct correlation within ±10% benefits in a short period.
between the automation effectiveness index and the capital Figure 19.30 shows a typical blend project implemen-
investment required for revamp or upgrades of the blending tation schedule using the pay-as-you-go strategy and indi-
system. On the other hand, the operation efficiency relates cates ROI and cost along the project timeline.
the additional benefits that can be expected from the capital
investment and improved operational efficiency. The ratio 19.8 Summary
of required capital investment and expected benefits results This chapter has discussed all technical and management
in an ROI period of 18–24 months, which is average in the aspects of a fuel blending system in a refinery. Because of
industry. The same methodology can be used to estimate space limitation, the focus has been mainly on the gasoline
the capital investments and tangible benefits for upgrading blending, but the concepts presented here can be extended
any state of automation of the blending system in a refinery. and applied to other fuel blending such as diesel and
fuel oils.
19.7.4 Project Implementation Strategy
It is not very uncommon in a refinery that is considering
Acknowledgments
the upgrade and revamp of the blending project to try to
The author thanks the management of Offsite Manage-
allocate $6–10 million for the capital investment before
ment Systems LLC, Sugarland, TX (www.globaloms.com),
going ahead for the project. More often the blending project
for permission to include most of the copyrighted figures
upgrade is put on hold and thus loses millions of dollars
and technology from their training manual—Strategic Fuel
every year from the quality giveaway and reblends due to
Blending Technology and Management.
specification violations. Therefore, it is a better strategy to

Automation Effectiveness Index

Totally Manual Fully Automated
Blending Blending
Operations 41 Operations
0 25 50 75 100

Operational Efficiency Index

All Tangible &
All Tangible Blending Achievable Blending
Benefits Lost 65 Benefits Realized

0 25 50 75 100

Fully
Totally Manual
Blending
Capital Investment Automated
Blending
Operations 41 Operations
0 25 50 75 100
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

3-5 MUS$ 6-9 MUS$

All Tangible Blending Tangible Benefits or Returns All Tangible &
Achievable Blending
Benefits Lost
65 Benefits Realized
0 25 50 75 100

6-10 MUS$ 10-15 MUS$

Basis: 300 KB/Day Refinery, Figures shown are representative and not actual for a refinery

Figure 19.29—Correlations between effectiveness/efficiency indices. Source: Reproduced with permission from [1].

Copyright ASTM International

AST-MNL58-11-0801-019.indd 496 3/12/13 2:52 PM

Chapter 19 n Fuel Blending Technology and Management 497

100 100
Implement and commission MP/MB Non-linear Offline
Blend Optimizer
90 90
Implement, customize
and Configure Tank Farm
Management System
80 80
Implement, customize and Configure Model based Tanks
Quality Tracking System

70 Install and commission online multi-analysis and multiplexed sampling

70
System (NIR)

60 Reconfigure Tanks Quality Tracking System

COST 60

% COST
to use online analysis at tanks inlets
ROI
% ROI

50 Design and Functional

Specifications of Field
50
Equipment Revamp
Strategy
40 40
Revamp of Field equipment, Automation and control loops /
Tank alignment work

30 30
Implement, customize and configure Online
Blend Control and Optimization System

20 20
User Training and Support

10 Final Integration and Testing of

10
Complete System

0 0
0 2 4 6 8 10 12 14 16 18
Elapsed Months
Figure 19.30—ROI versus implementation for a blending project. Source: Reproduced with permission from [1].

References [5] Agrawal, S.S., and Naughton, M.J., “Advanced Gasoline

[1] Offsite Management Systems, LLC (OMSLLC), “Strategic Fuels Blending-I,” Oil & Gas J., 103(7), 2007, p. 52.
Blending Technology and Management-Training Manual,” [6] Agrawal, S.S., Leong K.M., Wee L.H., and ECT James CTJ,
reproduced with permission from Offsite Management Systems, “Implementation and Benefits of Online Tanks Quality Track-
LLC, Sugar Land, Texas, USA, 2009. ing System in a Singapore Refinery,” Hydrocarbon Asia, 15(1),
[2] Ethyl Corporation, “The Ethyl Technique of Octane Predic- 2005, p. 36.
tion,” report no. RTM‑400b, 1981. [7] Agrawal, S.S., “Advances in Tank Quality Measurements Can
[3] Lambert, D., “Computation of Blending Indices,” PTQ, Q4, Help Cut Operational Costs,” Hydrocarbon Processing, 86(6),
2007, p. 135. 2007, p. 67.
[4] Naughton, M.J., and Agrawal, S.S., “Advanced Gasoline [8] Agrawal, S.S., “Model based Online Analysis and Monitoring
Blending-II,” Oil & Gas J., 103(7), 2007, p. 50. of Tank Qualities,” Paper presented at AICHE Spring National
meeting, Houston, April 24, 2007.

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20
Tank Farm Management
Suresh S. Agrawal1
20.1 Introduction Dome-shaped tanks are built to minimize the effects
Any liquid-based manufacturing facility, such as a refinery, of strong winds and they equalize the wind pressure better
petrochemical complex, beverage plant, etc., uses various than flat- or cone-shaped tanks. Figures 20.1 and 20.2 show
types and sizes of tanks to receive, store, and dispatch typical cone-shaped and dome-shaped fixed roof cylindrical
products. A cluster of such tanks is called a “tank farm” tanks, respectively.
and consists of 50 to 300 or more tanks in a refinery with,
for example, 100,000–600,000 bbl/day of crude oil process- 20.2.2.1.2 Floating Roof Cylindrical Tank
ing capacity. The efficiency and timely available informa- In this tank type, the top plate is not fixed and floats 8–12 in.
tion about the quality and contents of tanks can affect the above liquid separated by rim seals. It minimizes the fugitive
operations and profitability of the plant. This chapter will emission because of the low vapor gap between the liquid
discuss various aspects of tank farm management from and the top plate. This type of tank is further classified as an
its initial design methodologies to information manage- external floating roof tank or an internal floating roof tank.
ment technology and will limit the discussion to a crude The internal floating roof is similar to an external float-
oil refinery. Nevertheless, most of the discussion in this ing roof, but the top is covered with a cone or dome shape
chapter can also be applied to other relevant liquid-based and there is an internal floating roof. It is again suitable for
plants. liquids with higher vapor pressure. The internal floating
roof minimizes the leaks and fugitive emissions. Figures
20.2 Overview 20.3 and 20.4 show examples of internal and external float-
20.2.1 Purpose and Role ing roof types of tanks, respectively.
The purpose of a tank farm is to receive crude and other
feed stocks from external sources; store the intermedi- 20.2.2.2 Spherical and Bullet Tanks
ate products from onsite unit operations; and store the These tanks are used to store higher-pressure liquids and
final products before dispatch to customers by terminals, equalize pressure on the structure. Spherical tanks are
marine, truck, railcar, and pipelines. This section will dis- built onsite and hence are expensive to build. They are
cuss various types of tanks installed in a plant for storage built for large capacities. On other hand, bullet tanks are
of feed and products. low-pressure tanks and are built in shop; hence they are
less expensive than spherical tanks. They are meant for
20.2.2 Types of Tanks small-capacity storage and may be vertical or horizontal
There are three types of tanks used in a liquid-based plant: design. Figure 20.5 shows spherical and bullet tanks.
cylindrical tanks, spherical tanks, and bullet tanks (vertical
or horizontal). 20.2.3 Tank Types versus Product Types
Table 20.1 lists the types of tank used in a typical refinery to
20.2.2.1 Cylindrical Tanks store its crude feed and products.
These tanks are the most common types and are used to
store crude and products at atmospheric pressure. Their
roof shapes can be cone or dome shaped, and the roof type 20.3 Design of Tank Farm
can be fixed to internal or external floating roofs. A typical refinery or liquid-based plant uses the tanks for
feed receipts, intermediate products, and dispatch of final
20.2.2.1.1 Fixed Roof Cylindrical Tank products. Although plants are designed and built with
The top of the cylindrical tank is fixed and it may be flat, adequate storage capacity for design and future production,
cone, or dome shaped. It is suitable for smaller size and there are still the following situations in which there are
low-pressure applications. They are expensive to build serious economic effects on the refinery bottom–line:
because they require a thick top plate to resist deforma- • Crude oil is stocked up in excessive inventory;
tion and visible bending. Fugitive emission is the problem • Shipment is delayed because of insufficient products,
for this type of tank because of the vapor gap between the product storage capacity, or both; and
liquid and the top plate. • Process units are operating at less than optimal capacity.
The fixed roof can be cone or dome shaped. The cone- Figure 20.6 shows several stages of storage require-
shaped tank is easier to fabricate than the flat type of roof ment for a typical refinery.
and is less susceptible to spot deformation and bending. It There are methods to estimate the storage requirement
is used for large storage capacities. either at the front-end engineering design (FEED) level or

1
Offsite Management Systems, LLC, Sugar Land, Texas, USA
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499
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500 Petroleum Refining and Natural Gas Processing

Pressure/Vacuum Vent Roof Manhole

Fixed Roof Gauge – Hatch/

Sample Well
Float Gauge
Gauger’s Platform

Roof Column Spiral Stairway

Cylindrical Shell
Liquid Level
Indicator
Shell Manhole

Inlet Nozzle

Outlet Nozzle

Figure 20.1—Cone-shaped fixed cylindrical tank.

Peripheral roof vents Fixed-roof center vent

Fixed roof
(column-
supported)

Rim seal Tank shell

(vapor-mounted)
Sample port

Vacuum breaker

Ladder Gauge float

Deck leg Fixed-roof

support column

Access hatch Deck drain

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Chapter 20 n Tank Farm Management 501

Figure 20.3—External floating roof tank.

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Copyright ASTM International Figure 20.4—Internal floating roof tank.

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502 Petroleum Refining and Natural Gas Processing

Figure 20.5—Spherical and horizontal bullet tanks. Source: [1].

for expansion purposes after the plant is already operating. where:

These methods are discussed in the following sections. S = barrel of product storage per daily barrel of crude oil
processing capacity and
20.3.1 Empirical Correlations P = number of products produced by the plant (P = 8 for a
Nelson proposed an empirical formula for the estimation simple plant and P = 36 for a complex plant).
of tank farm size on the basis of refinery complexity as fol- Nelson later proposed an empirical formula for the
lows [2]: estimation of tank farm size on the basis of historical data
S = 1.75 × P + 10 (20.1) as follows [3]:

S = C + 4.5 × P + 11 (20.2)
Table 20.1—Types of Tank Used for Different where:
Refinery Products C = barrel of crude storage per day of crude oil processing
Tank Type Product Type capacity (C = 4 for refineries with crude supplied by pipe-
line and C = 55 for refineries receiving crude via tankers).
Floating roof cylindrical tanks Crude oil, gasoline, naphtha
Gary and Handwerk presented a “rule of thumb” for
Diesel, kerosene, FCC feedstock, the estimation of storage requirement [4]. They presented
Fixed roof cylindrical tank
residual fuel oil that 50 bbl of storage are required per barrels per day of
Normal butane, propane,
crude oil processed. They estimated this for a typical refin-
Spherical tank ery that receives and dispatches the crude and products by
propylene
pipelines. However, this estimate may be off for refineries
Bullet tank Isobutene, normal butane receiving the crude by tankers. They also presented that

CRUDE /
PROCESS INTERMEDIATE FINISHED
RECEIPTS PRODUCTS SHIPMENTS
UNITS PRODUCTS PRODUCTS
TANKS
BLENDER

Tankers Tankers

Blend Blended
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Stocks Products
Crude Oil

Pipelines
Pipelines

Trucks Intermediate Trucks

Other Feed Products
Stocks

Rail Wagons SLOPS Rail Wagons

Figure 20.6—Several stages of storage for a typical refinery. Source: [1].

AST-MNL58-11-0801-020.indd 502 3/12/13 2:57 PM

Chapter 20 n Tank Farm Management 503

Table 20.2—Tank Farm Storage for a Typical Refinery

Total Number Total Tank Average Tank Production Daily Production Days of
Number Area Name of Tanks Capacities (bbl) Capacity (kbbl) Factor (kbbl/day) Storage

1 Aromatics 13 173,171 13 0.10 22 8

2 Ballasts and slop 7 235,547 34 0.01 2 105

3 Butane + propane 7 234,591 34 0.04 9 26

4 Crude oil 9 4,917,680 546 1.00 225 22

5 Fuel oils 16 3,164,851 198 0.04 9 352

6 Gasoil 19 1,380,404 73 0.42 95 15

7 Gasoline 30 2,330,849 78 0.21 47 49

8 Kerosine 5 460,313 92 0.10 23 20

9 Naphtha 2 81,598 41 0.02 5 18

10 Process units 6 4,831 1 0.03 7 1

11 Propylene 3 35,217 12 0.03 7 5

12 Truck terminal 24 133,180 6 0.77 173 1

Total 141 13,152,230 93 1.00

storage capacities should be approximately 13 days for adequacy of existing tank farms at all three Kuwait refiner-
crude storage and approximately 25 days for product stor- ies through 2010 and developed a solution to the refineries’
age. tank farm needs for the refinery networks [6]. Because
Table 20.2 shows the data for a typical refinery with this work involved three refineries together in simulation
225,000 bbl/day of crude processing capacity. This refinery as opposed to the single refinery simulation by Barsamian
receives most of the crude by tankers (C = 55) and is fairly and Whitehead, it involved a non-Excel-based system and
complex (P = 36). linear-programming-based multiperiod and multirefinery
Table 20.3 compares the estimates of daily storage planning tools. This model also used Monte Carlo statistical
requirements by the above three methods and compares methods to simulate the uncertainties similar to those used
them with a typical refinery as shown in Table 20.2. by Barsamian and Whitehead [5]. This study just focused
on optimization tank farm usage by reallocating tankage
20.3.2 Statistical/Simulation Methods and changes in operations to minimize the usage of tank
Barsamian and Whitehead used historical data and a sta- capacities. The simulation predicted an overall savings of
tistical model to estimate the refinery tankage for a Taiwan approximately $2.5 million by the following changes in the
grassroots refinery [5]. Their model considered the follow- operations:
ing factors: • Reallocate existing tankage,
• Crude delivery and product shipment methods; • Inline finished product blending,
• Degree of refining complexity; • Inter-refinery transfers (IRT) of finished products, and
• Seasonal demands to create buffer storage; • Eliminate dual-port product loading.
• Plant turnarounds, shutdowns, and scheduled main-
tenance;
• Blocked operations using multiple feedstocks; Table 20.3—Comparison of Tank Farm
• Availability of inline blending; Storage Capacity
• Optimal levels of tank inventory to respond to market Estimated Daily
demands; and Storage/Crude
• Rental of tank storage if available off premises. Processing, No.
The model also inputs uncertainties such as ship Method Basis of Days
delays, lifting schedules, natural disasters, power failures,
Nelson (1959) Based on only refinery 73
and unit-stream factor, etc. Their model used Excel and its
complexity
built-in random number generator to perform Monte Carlo
simulation and optimized the tankage estimates using Nelson (1973) Based on refinery 69
Excel’s built-in linear programming solver. Barsamian and complexity and mode
Whitehead reported a 20 % savings with 95 % confidence, of crude receipts
resulting in a total savings of $58 million in capital invest- Gary et al. (1994) Rule of thumb 50
ment for the Taiwan refinery [5].
Actual refinery Existing refinery 58
Al-Otaib and Stewart used more elaborate simula-
storage storage Table 20.2
tion and linear programming techniques to determine the
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504 Petroleum Refining and Natural Gas Processing

Figure 20.7—Tank capacity utilization before optimization.

Figure 20.8—Tank capacity utilization after optimization.

Figures 20.7 and 20.8 show the tank capacity utiliza- 20.4.1 Tank Inventory
tion before and after model optimization and clearly dem- It is extremely important that the inventory of a tank in
onstrate that the simulation techniques used by Al-Otaib the tank farm be available in near real time for inventory
and Stewart for three Kuwait refineries were a success. control/management, to avoid spills during loading, and to
They reported a payback period of 2 years [6]. safely operate the plant. This requires the measurement of
the following five tank process parameters:
20.4 Required Tank Information 1. Level (mandatory),
and Methods 2. Pressure (mandatory for high-pressured tanks),
The management of a tank farm requires that the following 3. Temperature (mandatory for custody transfer and for
information be available to various departments/personnel heated tanks),
in an online/offline manner to manage the plant efficiently, 4. Density (mandatory for mass-based custody transfer),
safely, and economically: and
• Tank inventory, 5. Water level (optional but recommended for crude and
• Tank qualities, and fuel tanks).
• Estimate of fugitive emission. These parameters are measured manually or by an auto-
The following sections will discuss the methodologies matic tank gauging (ATG) system as shown in Table 20.4.
and technology for each these methods. These methods are discussed in the following subsections.

Table 20.4—Methods and Purpose of Tank Process Variables

Method(s) of
Process Variable Measurement Purpose of Measurement

Level Manual, ATG • Issue alarms to avoid spills

• Inventory calculations

Temperature Manual, ATG • Fugitive emission control and calculations

• Temperature compensation in inventory calculations

Density Laboratory, ATG, mass • Mass-based inventory calculations

flow meters

Pressure ATG or none • Fugitive emission control and calculations

• Safety for pressurized tanks

Water level ATG or none • Limit water content and purge excessive water because it
is detrimental to process units
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Chapter 20 n Tank Farm Management 505

20.4.1.1 Manual Measurements measures effects caused by the changing liquid position. We
of Tank Parameters have listed some of the most common techniques used in the
Although manual measurements of tank parameters are industry for direct and inferential (indirect) methods.
almost nonexistent for more than 50-kbbl/day-capacity • Direct method techniques:
refineries, they are still in practice for smaller refineries. In • Direct visual observation on a calibrated scale
this method, two people climb up a tank at least 2 times a (e.g., gage stick, hook gage, or gage glass);
day and measure the level by using a calibrated gage tape • Direct position of a float on the liquid surface;
and visual observation. They would then enter this informa- • Contact of electrode probe with liquid surface;
tion in the tank information system (TIS). This method of • Interruption of light beam to photoelectric cell;
level measurement not only poses safety concerns but also and
illustrates that an inaccurate level measurement of ±6 mm • Reflection of radio, radar frequency, or sonic
multiplied by all tanks will considerably deviate the actual waves from a liquid surface.
inventory estimate from such measurement. • Indirect or inferential method techniques:
• Measurement of hydrostatic pressure,
• Measurement of buoyant forces exerted by par-
20.4.1.2 Automatic Measurements tially immersed object,
of Tank Parameters • Thermal determination between liquid and vapor
20.4.1.2.1 Hybrid Gauging System phases,
A hybrid tank gauging system uses different instrument • Based on physical or electrical properties of liquid
and technology for the measurement of tank parameters, to infer surface position, and
namely level, temperature, density, pressure, and water • Attenuation of radiation through liquid and vapor
level. We will briefly discuss only a few of the methods phases.
for the measurement of each of the process parameters Next, we will discuss the pros and cons for two of
because there are too many to enumerate in this chapter. the most common techniques for each of the methods:
the float type gage and the reflection of waves from the
liquid surface for the direct method and measurements
20.4.1.2.1.1 Tank Level Measurement There are two of hydrostatic pressure and buoyancy forces by a partially
categories of methods for the measurement of tank level: immersed object for the indirect method. Figure 20.9 shows
the direct method and the inferential method. The direct the schematic diagrams of these two methods by direct and
method directly measures the liquid height compared with a indirect methods, and Table 20.5 compares the pros and
datum reference line. On the other hand, the indirect method cons of the same.

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Direct Method-Float Type gauge Direct Method – Wave Refection from liquid Surface

P = k* ρ * H
Where
k = Constant
ρ = liquid Density
H = Liquid Height
H

Indirect Method – Measurement of hydrostatic pressure Indirect Method – Meas

Measurement
rement of Buoyancy
B o anc force

Figure 20.9—Direct and indirect methods of level measurements. Source: [1].

AST-MNL58-11-0801-020.indd 505 3/12/13 2:58 PM

506 Petroleum Refining and Natural Gas Processing

Table 20.5—Summary of Pros and Cons of Direct and Indirect Methods of Level Measurement
Advantages Disadvantages

• Can be used for unlimited tank height • Intrusive sensors

• Excellent accuracy of 4–5 mm • Mechanical devices are subject
• Comparatively low cost to wear, corrosion, failure, and
Float type gage
• Can be used for low- to medium- “getting stuck”
pressured tanks • Subject to material buildup causing
loss of accuracy

Direct method • High accuracy of 0.5–1 mm • Can be applied for still liquid and
• No moving parts, nonintrusive not turbulent liquids
components • Higher cost compared with other
Wave reflection from • Low maintenance, operational, and technologies
liquid surface ownership cost; high mean time • Cannot measure interface
between failures (MTBF) of >60 years • Effective for liquid and slurries
• Modular design to install in operation but requires caution for granular
material

• Simple and familiar technology • Must be corrected for density

• Reliable method to measure level, • Susceptible to fugitive emission
density, mass, and volume • Requires additional valves and pipes
Measurement of
• Can be calibrated from pressure • Useful only for clear liquid
hydrostatic pressure
standard applications
• Reasonable cost • Not practical for slurries
Indirect or inferential • Typical accuracy is ±0.03 %
method
• Limited motion and few moving parts • Calibration is density-dependent
Measurement of • Proven for difficult hydrocarbon • High cost with long spans
buoyant forces by applications • Awkward to install and requires
partially immersed • Can be used for high temperature and careful and constant maintenance
object pressure • Buildup on displacer can affect
• Can measure interfaces accuracy

20.4.1.2.1.2 Temperature Measurement The temperature 20.4.1.2.2 Multifunction Gauging System

in a tank can be measured either at one point for a well- A multifunction gage uses a single instrument to measure
mixed tank or at multiple points for a stratified tank. In the all required parameters such as level, multiprofile tem-
case of the latter, tank temperature is typically measured at peratures and density, pressures, water levels, and tank
16 or so points using multiresistor thermometers and then empty space vapor pressure without the use of multiple
averaged over all of those points to calculate an average tank instruments for each measurement. It consists of 4–12 mea-
temperature. surement modules installed on a single steel pipe installed
through only one tank opening.
20.4.1.2.1.3 Density Measurement The measurement A multifunction gage is a single instrument to provide
of density is measured by the hydrostatic (HTG) method to all necessary data to calculate volume by either the hybrid
measure pressures at two points and then infers the average method (level, temperature, density, and water) or the hydro-
liquid density from their values using equation 20.3: static method (mass, density, and water) in real time directly
from the gage. Its transmitter can support over 1,000 strap-
ping points and can provide diagnostic measurements, raw
P2 – P1 = k × ρ × H (20.3)
measured data, or calculated data. It is the perfect gage for
use with distributed control system (DCS), supervisory con-
where: trol and data acquisition (SCADA), and HMI software [1].
P = pressure at point 1 and 2, A multifunction tank gage has the following features:
k = constant, • It provides the most accurate volume measurement
ρ = density, and for custody transfer, inventory, or loss control on the
H = distance between points 1 and 2. market by a tank gage.
It is assumed that the liquid density is the same • It provides real-time volume by hybrid or hydrostatic
between points 1 and 2 and it may not be valid for a strati- methods (all product variables are measured from one
fied tank. instrument, one tank opening, one electrical connec-
tion, etc.).
20.4.1.2.1.4 Pressure Measurement The tank pressure • It provides real-time profiling of product within a liq-
is also measured traditionally by a hydrostatic method using uid storage tank (water, density, and temperature strati-
pressure transmitters at a lower point above the water and fication). It does not require additional instruments,
sediment level. --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
tank entries, electrical connections, etc.
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Chapter 20 n Tank Farm Management 507

• It determines the product quality (i.e., specific gravity, The tank inventory calculations require tank param-
free water, and entrained water content in product). eters (height, diameter, and unusable volume), characteris-
• It provides vapor pressure and vapor temperature tics data (strapping table), and dynamic process parameters
for hydrocarbon emissions reporting, gas blanketing (level, temperature, density, pressure, water level). This
regulation, or alarm indication of a stuck pressure process is shown in Figure 20.11.
relief vent. The following steps are required, either manually or via
• It is certified for leak detection (mass sensitivity). software, to calculate tank inventory and other information
• It provides volume calculations using measured vari- needed for the real-time management of tank farm.
ables for multistrata density (not reference/average • Step 1—Calculation of raw volume from liquid level
density), free and entrained water (not just free water), measurement: There are three methods available to
actual vapor pressure and temperature, actual atmo- convert liquid level to tank raw volume (i.e., without
spheric pressure and temperature, actual mass, etc. any temperature adjustment):
• It has no moving parts. • Strapping table: This is a table of tank volume
• It is self-diagnostic and self-calibrating. versus tank level at very small intervals provided
• It is bottom referenced (standard). No reference point by the tank manufacturer in the form of a printed
error as with roof-mounted level technologies. tabular format. It is useful for a deformed and aged
• It installs in service with or without a gage well. tank and is also necessary for noncylindrical tanks
• When installed within the gage well, it provides a direct because tank geometry is not uniform with respect
comparison of the ATG with the metrology reference to height. Because this table is very long, it is very
point (i.e., the manual hand line and samples at the resource-consuming for programming in a tank
same physical location on the tank for level, tempera- information automation system. This is especially
ture, density, and water. Thus, reducing measurement true if the plant has old tanks and the tank tables
errors caused by multiple data locations from other were only provided on papers and not in electronic
hybrid-level gages. format.
• It has the lowest cost of ownership among inventory • Strapping factor: This can be calculated very eas-
tank gauging technologies and the most benefits. ily to use as rough estimate of volume at a certain
level using a simple calculator. It is accurate for
20.4.1.3 Inventory Calculations cylindrical tanks and is easier to program. It is use-
20.4.1.3.1 Methodology ful for calculating flow rates in and out of the tank
In this section, we will discuss and enumerate the steps to on the basis of level changes and to estimate time
calculate tank inventory, our ultimate goal, in a step-by-step for emptying and filling.
procedure. However, to understand the various terms that • Mathematical formulas: This method uses the
will be used in this section, let us examine a tank and its mathematical equations to calculate for a given
physical characteristics as shown in Figure 20.10. tank geometry, but it cannot be used very easily

Tank Diameter, D

Vapor Space
Volume, Vv
High-High Alarm

High-Low Alarm
Ullage or Void
Volume, Vu
Tank Height, H

Liquid Level

Raw Volume, Vl
Water Level
Low-High Alarm Water Volume, Vw
Low-Low Alarm
Non-Pumpable
Volume, Vnp

Figure 20.10—Tank’s anatomical parameters. Source: [1].

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`

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AST-MNL58-11-0801-020.indd 507 3/12/13 2:58 PM

508 Petroleum Refining and Natural Gas Processing

Temperature
Compensation
Tank Parameters and Algorithm
Characteristics Data

Receipts
Measurements of Calculation of
Level, Temperature, Tank Inventory
Pressure, Density, (Volume and
Water Level
Mass)
Dispatch

Integration with
Enterprise
Database and
Control Systems

Figure 20.11—Flow diagram for the measurement and calculation of tank inventory calculation. Source: [1].

using a simple calculator. However, it is accurate • Step 2—Temperature compensation of raw volume:
for all tank geometries and may have errors for Because the tank volume is dependent on the tempera-
deformed and aged tanks. It is not difficult to ture, the raw volume cannot be used for custody trans-
program and is more accurate than the strapping fer purposes and hence must be standardized to either
factor. Figure 20.12 illustrates the mathematical 15 or 20°C using ASTM Table 54 and ASTM D125-80,
formulas used for common tank shapes in a plant. respectively. This procedure can be used by using the

D
Total Volume , Vt = π * D2 * H
4
Cylindrical H Partial Volume , Vy =
π * D2 * y
y
4

D
Total Volume , Vt =
π * D3
6
Spherical
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

y
π * y2 * (1.5*D -y)
Partial Volume , Vy =
3

H Total Volume , Vt =
π * D2 * H
4
Horizontal Partial Volume , Vy =
H * D2*(θ - Sinθ)
D
Cylindrical 8
Where θ (radian) = 2 * Sin-1(2 * Sqrt ( y*(D-y) ) / D)

D
Total Volume , Vt =
π * D2 * H
+ π * D3
Vertical Bullet 4 6
= π *D * π * D3
2 y
H +
(Not very common) Partial Volume , Vy
4 6

Total Volume , Vt =
π * D2 * H + π * D3
H 4 6
Horizontal D
Partial Volume , Vy =
π * y2 * (1.5*D - y) H * D2*(θ - Sinθ)
3 8
Bullet Where θ (radian) = 2 * Sin-1(2 * Sqrt ( y*(D-y) ) / D)

Figure 20.12—Calculation of tank volumes by mathematical formulas. Source: [1].

AST-MNL58-11-0801-020.indd 508 3/12/13 2:58 PM

Chapter 20 n Tank Farm Management 509

FORTRAN program available from ASTM and is not a • Compensated volume,

manual calculation. The temperature used for the cal-
culation of compensated volume must be the average Vcomp = Vgross × VCFACT, (20.5)
temperature to account for the temperature stratifica-
tion in the tank.
• Step 3—Calculations of tank mass: This step calculated where VCFACT is the temperature compensation factor
the tank mass using the temperature-compensated vol- calculated using ASTM methods at the reference tem-
ume from step 2 and density measurement at 15 or 20°C perature of 15 or 20°C.
either in the laboratory or using the automatic measure- • Void volume,
ment from the tank gauging system or mass flow meter.
• Step 4—Calculation of net volume, mass, and other Vvoid = Vmax capacity – Vgross. (20.6)
information: This step uses the tank geometry using the
nonpumpable volume to calculate the net mass and net
• Percent void volume, which measures the void space at
volume of the tank for custody transfer, loading, and
the top of the tank,
unloading purposes. Historical information is also at
this step to calculate the status of tank movement at
any instant. % Vvoid = Vvoid × 100/Vmax capacity. (20.7)
Figure 20.13 shows the above steps for the calculations
of tank inventory from measured tank process parameters • Nonpumpable volume (Vnpv) is the fixed and known
and tank characteristics. characteristics of the tank and it represents the volume
at the bottom of the tank that cannot be pumped out
20.4.1.3.2 Equations because it is below the suction line of the pump.
This section enumerates all equations used in a typical tank • Maximum available volume,
inventory calculation and management system.
• Gross or raw volume,
Vmax = Vmax capacity – Vnpv. (20.8)

Vgross = level × strapping factor, (20.4)

• Gross weight,

or look up from strapping table or calculate using tank

Wgross = Vgross × density at reference temperature (20.9)
geometry and calculation equation.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Methods Steps Information
• Manual Tape Measurement Liquid & Water
• Automatic Gaging Systems Levels

• Strapping Table • Tank Geometry

Raw Dimensions
• Average Strapping Factor
Volume • Non-Pumpable
• Exact Mathematical Formula Volume

• Manual Measurement of Temperature • @ 15o C using ASTM

Temperature or None Compensated Table 54 Method or
@ 20o C using ASTM
• Automatic Gaging Systems Volume
D125-80 Method

• Lab Analysis of Density

Mass
• Automatic Gaging Systems
Calculations
• Mass Flow Meter at Tank Inlet

Net Volume, Net Mass

and Miscellaneous
Calculations

Figure 20.13—Steps to calculate tank inventory parameters. Source: [1].

AST-MNL58-11-0801-020.indd 509 3/12/13 2:58 PM

510 Petroleum Refining and Natural Gas Processing

• Net available volume, 20.4.2.1 Laboratory Analysis

First, we will discuss the method of laboratory sample
Vnet = Vgross – Vnpv. (20.10) and analysis for the tank qualities. In this method, the
laboratory technician collects the tank samples 2–3 times
either weekly or daily on the basis of the criticality of the
• Net weight, qualities and analyzes them in the laboratory. Once, the
results are available, they are entered manually in the LIMS
Wnet = Vnet × density at reference temperature (20.11) (laboratory information system) and are available to other
applications such as blending, planning, and process unit
• Tank status is estimated by comparing the old level control and optimization systems. Laboratory analyses are
versus the current level within a measurement error available online only after a delay of 2–8 h, and the qual-
tolerance. ity of the source may change in the meantime. Despite its
• Rate of change of level and estimation of tank fill-up or delayed availability, it is the most common method of tank
emptying can be estimated as shown in Figure 20.14. quality analysis.
Agrawal suggested a method to easily estimate the lab-
20.4.1.3.3 Advanced Inventory Management oratory analysis load in a plant and be able to determine the
• Tank leak detection: If there are flow meters installed at benefits of other methods to compensate for the cost and
tank inlet and outlets, then any leak can be detected by availability of the laboratory analysis results to users [7].
making a balance of total input/output flow and volume Agrawal defined a laboratory analysis load measurement
changes from the tank gauging system. However, varia- parameter, SQS, as follows [7]:
tion in tank levels due to surface wave ripples should be
considered before calculating actual volume changes. SQS = S * Q * S (20.12)

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
• Flow meter calibration offsets: Just like leak detection,
calibration of flow meters installed at upstream and where:
downstream points of the tank can also be checked if S=n umber of source (tanks or process streams) sampling
the flow balance around the tank does not close within points,
2 % for a steady tank. Q = number of qualities analyzed per sample, and
• Mass reconciliation and oil loss estimation: By balanc- S = number of samples per tank.
ing input and output flow and changes in tank inven- The higher the SQS, the higher is the cost of labora-
tories around a boundary of the tank farm, an estimate tory analysis to the plant. Agrawal analyzed a laboratory
of oil loss can be arrived at in real time using a well- sample schedule and analysis for a typical 300-kbbl/day
featured tank inventory management software system. refinery for analyses of onsite units and offsite tanks, and
he summarized the frequency of SQS load, which is shown
20.4.2 Tank Qualities in Figure 20.15 [7].
In addition to tank inventory, it is extremely important to The distribution of SQS load in Figure 20.15 shows
know the qualities of tank for the following purposes: that tank qualities are analyzed more often, but both
• Tank certification before final sale to customer, samples are taken and qualities are analyzed less frequently.
• Qualities of feed material purchased from external On the other hand, more process unit streams are sampled
sources, and analyzed but with a lesser frequency as evident from a
• Input feed qualities to process units, and flatter frequency plot for onsite (process units) operations.
• Qualities of the blending component tanks to control The concept of the SQS parameter for laboratory
the blend recipe. analysis can also be used to estimate the cost of labora-
These tank qualities are obtained in two modes: offline tory load in a plant within ±10 % and can be adjusted for
mode by laboratory samples and analysis and online mode a specific plant’s laboratory operations. We have estimated
by using the online analyzers. We will discuss these meth- the typical times taken by a laboratory technician to go and
ods in the following sections. get a sample from a stream or tank and perform analyses

Time Left = Void Vol / Rate of Change of Volume

Rate of Change of Volume = Rate of Change of Level *

Cross Sectional Area of Tank

Cross Sectional Area of Tank = π* (Diameter)2/4

Rate of Change of Level = (Level @ Time T2 - Level @ Time T1)

(T2 - T1)

Figure 20.14—Method to estimate time for cylindrical tank emptying and filling.
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Chapter 20 n Tank Farm Management 511

Lab Sample/Analysis Frequency Distribution for a Typical Refinery

Data Used from an Actual Refinery
20

18 OFFSITE ONSITE
OPERATIONS
OPERATIONS
16

14
Frequency / Year

SQS=NSource*NQuality*NSample
Figure 20.15—Typical laboratory analysis loads for onsite and offsite unit qualities. Source: [7].

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
of qualities in the laboratory. The analysis time could vary We will later discuss that the above cost analysis
anywhere from 10 min to 2 h (octane) depending on the methodology for the laboratory analysis load in a plant
quality analyzed. We have assumed that on average it takes can be used to evaluate other methods of quality analyses
30 min to analyze a quality. Also, the labor cost for sam- of tanks.
pling and analyzing may be different. We have taken all
of these factors into consideration to estimate the cost of 20.4.2.2 Online Analysis
laboratory load for a refinery with 44 tanks and 23 process Because some operations, such as unit control and optimi-
streams. This cost analysis for a 300-kbbl/day refinery is zation, and fuel and crude blending are critical to receive
shown in Figure 20.16. the qualities in near real time or within a short interval,

Summary of Refinery Lab Analysis Cost

Onsite Offsite
Number of process streams 23
Number of tanks 44
Sampling time 0.5 0.5
Sampling manpower rate, $/hr 25 25
Sampling cost, $/sample 12.5 12.5
Lab analysis; time/analysis 0.5 0.5

Analysis manpower, $/hr $40 $40

Analysis cost, $/analysis-sample $20 $20
Yearly SQS load 162,060 57,566

Total cost of sample collections $314,813 $85,800

Yearly cost of lab analysis, $ $3,241,200 $1,151,314
Total cost sampling + analysis $3,556,013 $1,237,114
Total cost lab analysis of onsite + offsite, $ $4,392,514
Average cost, $ / SQS $20
Yearly SQS Load = Total Number of Samples/Day *
(Number of Analyses/Sample) * (365days/Year)

Figure 20.16—Typical cost of laboratory analysis for a 300-kbbl/day refinery. Source: [7].
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512 Petroleum Refining and Natural Gas Processing

plants started installing online analyzers. The installation of qualities are already outdated and the blend recipe may
the online analyzers has following characteristics: be off, resulting in either violation requiring reblends
• Most online analyzers are installed at the exit points of or quality giveaways.
process unit streams to control unit operations. • Online analyzers such as near-infrared (NIR) analyzers
• Process unit outlet stream analyzers can also be at the are expensive and are utilized only during the blend
inlet to a storage tank. runs. If only one blend batch of 8–10 h is executed per
• Online analyzers are also installed at the location of day, then the online analyzers are used only for 35–40 %

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
tank exits such as for gasoline/diesel/fuel oil inline of the day.
blending. Figure 20.17 shows the online analyzers installed on
• A plant may also have analyzers installed at the blend the process stream at the exit of process units. This may
header outlet that can thus indicate the qualities enter- also require laboratory analyses for the same analyzed qual-
ing the final product tank. ity for analyzer validation or of a different quality that has
• Online analyzers may be either discrete (one stream/ no online analyzers. Sometimes laboratory qualities may be
one quality) or integrated (one stream/many qualities). manually input as constant values for unchanging qualities
• Online analyzers may be multiplexed (shared) to give for streams (e.g., butane, methyl tertiary butyl ether, etc.).
one or many qualities of more than one stream. Recent advances in quality-predictive methods have
Online analyzers improved the availability of the qual- enhanced the usability of online analyzers, specifically
ity results in real time for process streams and for blending those used in blending operations, and have made the blend
tank qualities for blending control during blending execu- component tank qualities available in real time for all con-
tion. However, the online analyzers installed at the exit of trol applications, planners, engineers, and operators. This
the blending component tanks did not quite minimize or method developed by Offsite Management System, LLC is
eliminate the need for laboratory analysis. Let us discuss discussed in the next section [8].
the shortcomings of blending analyzers at the exit of the
blend component tanks. 20.4.2.3 Model-Based Tank Quality Estimation
• The qualities of blend component tanks are analyzed This method uses the same linear/nonlinear blending rules
only during the actual blend execution. At other times, and models used in the advanced blend control optimiza-
they are turned off except for continuous blenders. tion planning system that is commercially available and it
• During a nonblending period, the component tank has the following characteristics:
qualities are again analyzed only by the laboratory and • The online analyzers, either discrete or integrated, are
results are only available sometimes 2–8 h later. installed at the inlet of the blend tank components as
• The blending planner or engineer cannot plan a new opposed to installing them at the exit of the tank.
recipe until the blend component tank qualities are • An online software system tracks the qualities of the
available to them. tank inlets and, integrated with the tank contents from
• If the blend tanks are running (i.e., feeding as well) dur- historical data, applies blending models to calculate
ing the blending operations, these laboratory-analyzed the blending quality of the component tank.

Figure 20.17—Example of online and laboratory analysis for a run-down diesel blending system. Source: [1].
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Chapter 20 n Tank Farm Management 513

• The software system tracks not only the qualities but cumulatively cause concern for environmental pollution.
also the composition of tanks for mixing model and It would be impossible to cover all technical and environ-
density/quality segregation to predict the quality at the mental aspects of fugitive emissions in this chapter. Hence,
tank outlet during blending. we will focus briefly here only on fugitive emissions from
Figure 20.18 shows a schematic diagram of the model- the following types of aboveground tanks to give readers an
based tank quality tracking system (gomsTQTS™) devel- introduction to the material.
oped by Offsite Management Systems, LLC [8].
An optional online analysis as shown in Figure 20.18 is 20.4.3.1 Storage Tanks
to install online analysis points at the inlet of the compo- 20.4.3.1.1 Fixed Roof Tanks
nent tank, in which case the installation of a sampling point Although they are the least expensive, fixed roof tanks
at the outlet of the tank becomes redundant. This is because are mainly used for storing low-pressure liquids. The

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
the tank qualities will be calculated by the quality tracking emissions from this tank are caused by the changes in
module from the tank inlet qualities. temperature, pressure, and liquid levels while filling and
Details and a case study of the above system installed emptying tanks. When the tank is filling, the displaced
in an actual refinery can be found elsewhere to minimize vapor vents directly to the atmosphere and fresh air fills in
the discussion in this chapter [8]. One of the drawbacks when the tank is emptying. This tank has minimal control
of this method is the long distance involved between the over the fugitive emissions, and refineries are burdened
sampling and analysis points, but manufacturers of the with estimating the total vapor discharged per year on
NIR/nuclear magnetic resonance (NMR) system claim that the basis of tank movements. This type of tank is also
sampling points can be as far as 2-3 km apart through the fitted with a pressure vacuum vent to bring in the fresh
use of fiber optics. air on cooler evenings to balance the pressure below the
vent pressure, thus minimizing the vapor discharge to the
20.4.3 Fugitive Emission atmosphere.
Fugitive emissions are the unintentional release of mate-
rial from equipment and they can occur from any leaking 20.4.3.1.2 Floating Roof
equipment such as pumps and compressors, storage and There are three types of floating roof tanks used to over-
processing vessels, flow control and pressure relief valves, come the shortcomings of the fixed roof tanks.
pipelines, tanks, etc. Although the fugitive emissions are • External floating roof tanks: They have an open-ended
small in quantity, their origin exposes workers and they cylindrical steel shell that floats on the liquid surface

Tank Inventory
and Quality
Planning and Database
Scheduling

Movement
Schedule

Composition
Tracking Module Quality
Quality Historizer
Tracking Module
Optional Online

Inventory,
Analysis
Receiving

Composition,
Schedule

Flow, Quality

Quality

Redundant
Quality Blending Analysis and
Online
Analysis Module Reports

A A
Predicted Quality

Model Bias

To Blend
Non-linear
Process Streams

Control
QualityModels
Sample
Manual

Manual Sample /s
Lab Analysis Quality Error
Estimator

Figure 20.18—Advanced model-based tank quality tracking system. Source: [8].

AST-MNL58-11-0801-020.indd 513 3/12/13 2:58 PM

514 Petroleum Refining and Natural Gas Processing

to minimize the vapor space above the liquid level. The to tank walls or change in vapor space due to the rising
emissions from this tank are less than the fixed roof liquid level in the tank. They are estimated as follows:
tanks and limit losses from the rim seal system, fittings,
exposed liquid on the tank walls after the liquid is with- LW = 0.0010 MV PVA QK N K P (20.14)
drawn (emptying tank), and the roof lowers.
• Internal floating roof tanks: These have an improvement where:
over the external floating tank by installing a fixed MV = vapor molecular weight;
roof to protect from sun and rain. They have limited PVA = v apor pressure at daily average liquid surface
emissions from docks fittings, docks seams, and the temperature;
annular space between the floating internal roof deck Q = annual net throughput, bbl/year (tank capacity,
and the tank wall. Top and side vents on the fixed roof bbl times annual turnover rate);
allow for the discharge of vapor. The fixed roof may be KN = turnover factor, dimensionless, for turnover >
dome shaped to block winds and minimize evaporative 36/year, KN = (180 + N)/6N for turnover ≤ 36 KN = 1;
losses. N = number of tank volume turnovers per year; and
• Closed floating roof tank: This type of tank has closed KP = working loss product factor, dimensionless, for
vents on the fixed roof and a pressure-vacuum vent crude oil = 0.75, for all other liquids = 1.0.
uses injection of an inert gas (e.g., nitrogen) to balance The U.S. Environmental Protection Agency (EPA) pro-
the pressure variation and provide essentially a zero- vides Tank 4.0 (http://www.epa.gov/ttnchie1/software/tanks/
emission tank. index.html) software for the calculations of fugitive emis-
sions from tanks, and it generates detailed reports. This
software is available free of cost and may be downloaded by
20.4.3.1.3 Pressure Tanks
anyone [9]. Further information can be obtained from the
Pressure tanks are spherical or bullets used for storing
EPA document found at http://www.epa.gov/ttn/chief/ap42/
gases with high pressure such as butane and pentane.
ch07/index.html [10]
These tanks are equipped with pressure-vacuum vents to
minimize losses from boiling and breathing loss from tem-
perature and pressure changes.
20.4.3.3 Methods to Detect Fugitive Emissions
Some common methods to detect the fugitive emissions
from field equipment such as valves, relief valves, compres-
20.4.3.2 Estimation of Emissions Losses sors, pumps, drains, etc., are
• Standing losses (Ls): These happen when the tank is • Portable gas detectors,
steady and are due to breathing of vapor above the liq- • Catalytic beads,
uid surface. They are estimated as follows: • Nondispersive infrared detectors,
• Photoionization detectors,
LS = 365 VV WV K E K S (20.13) • Combustion analyzers, and
• Standard gas chromatography with flame ionization
where: detectors.
MV PVA
W=
RTLA
∆TV ∆PV − ∆PB 20.5 Oil Movement
KE = + 20.5.1 Overview
TLA PA − PVA
One of the most manpower-intensive activities in a typi-
1 cal refinery is the movement of liquid material in and
KS =
1 + 0.053PVA HVO out of tanks in and across the plant boundaries. This is
VV = vapor space volume, m3; compounded by the problem of handling various equip-
WV = vapor density, kg/m3; ment such as tanks, pumps, motor-operated valves, mixers,
KE = vapor space expansion factor, dimensionless; manual valves, and flow and temperature measurements.
KS = vapor space saturation factor, dimensionless; Agrawal (1996) summarized and compared the number of
365 = days/year; equipment/instruments used in oil movement activities in
MV = vapor molecular weight; nine refineries as shown in Table 20.6 [11].
R = universal gas constant, mmHg·L/K·mol; The number of limit switches is not shown in Table
PVA = vapor pressure at daily average liquid surface 20.6 because they are generally not available. However, a
temperature; good guess would be that approximately 25–30 % of strate-
TLA = daily average liquid surface temperature, K; gic manual valves have limit switches.
TV = daily temperature range, K; The management of the equipment and efficient opera-
PV = daily pressure range, mmHg; tion of material movement activities in Table 20.6 is termed
PB = breather vent pressure setting range, mmHg; oil movement and storage (OM&S), and we will discuss the
PA = atmospheric pressure, mmHg; following technical, management, and economical aspects
HVO = height of a cylinder of tank diameter, D, whose of such OM&S in this section:
volume is equivalent to the vapor space vol- • Problems and challenges,
ume of a fixed roof tank, including the volume • Operational data analysis,
under the cone or dome roof, ft. • Estimation of automation incentives,
• Working losses (Lw): When the tank is either emptying • Automation technology and strategy, and
• OM&S automation project implementation.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

or filling, the losses occur because of liquids adhered

AST-MNL58-11-0801-020.indd 514 3/12/13 2:58 PM

Chapter 20 n Tank Farm Management 515

Table 20.6—Comparison of Oil Movement Equipment in Nine Refineries

Other Refineries
1 2 3 4 5 6 7 8 9
Storage Tanks

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Remote level & temp 218 460 190 125 180 83 265 120 124
Local level & temp 180 120 40 304
Valves
Remote operations 1400 2000 490 160 400 300 320 200 31
Motorized (local) 250 200 67
Limit switches
Manual 4000 3600 1950 465 300 700 2000 2532
Pumps
Remote operations 60 330 106 95 100 130 28 100 20
Remote status 9
Remote mixers 220 72 70 50 45 2 20
Line segments 2300 1200 430 1200

20.5.2 Problems and Challenges which may be at times very expensive for the refinery’s
It is quite natural that the management of such a large and profitability.
complex network of equipment and transfer activities in a • Line-up errors: The refinery has a very complex network
refinery has some problems associated with it. Problems of pipelines and field equipment. To line up various
typically associated with OM&S activities can be classified valves, pumps, etc., for a transfer activity requires care-
into the following four areas: ful execution and may result in product contamination
1. Decrease in plant profitability, if any errors are made in the line-up. Line-up activity
2. Operating losses, by itself is also time-consuming and requires the avail-
3. Product losses, and ability of field operators in a timely fashion.
4. Operating costs. • Product contamination: This may be the result of line-
The following sections will discuss each of these problem up errors or unplanned or unauthorized movements.
areas in detail. • Pump cavitations: This situation could occur if the
valve before the pump is stuck or does not open fully.
20.5.2.1 Decrease in Plant Profitability Failure of the valve downstream of the pump could also
The plant profitability may be decreased because of the fol- damage the pump.
lowing factors: • Floating roof sinking: This problem may occur if the
• Product quality, quantity giveaway, or both: This is liquid in the tank falls below a certain level because of
encountered in activities such as blending and custody a lack of timely action by the operator due to failure of
transfer because of a lack of inline blending and accu- a low-level alarm.
rate measurements.
• Product degradation due to displacement of previous 20.5.2.3 Product Losses
line material: Transfer of products of different qualities The direct effect of product losses is the decrease in plant
in activities such as tank-to-tank transfer, tank-to-ship profitability, and the following factors contribute to this
transfer, etc., in the same pipeline segment degrades problem area:
the products. The product degradation usually requires • Inadequate or erroneous measurements or both: OM&S
selling the product at a lower price or quality correction activities involving movement of products across the
by reblending or addition of corrective components. refinery boundaries such as custody transfer and
marine loading/unloading may incur product losses
20.5.2.2 Operating Problems just because of inadequate or erroneous measurements.
Operating problems vary from areas related to man/ • Unplanned and unauthorized movements: These are
machine interfaces to errors by field operators and they related to human error by the operator, field operators,
may result in economic losses. Some of most common or both. The product loss may occur in terms of the
operating problems are need to reprocess the contaminated products or sell at
• Multiple operator interfaces: It is one of the major a lower price because of its downgraded quality.
concerns of the OM&S operations in a refinery as the • Leaks: Product leaks from valves and tanks result not
operator has to work with as many as 7-8 different only in products losses but also present environmental
types of displays and systems such as tank gauging sys- hazards. An unattended tank during its filling or failure
tem, DCS workstations, blend control, MIS computer, of a high-level alarm may cause spills and thereby the
laboratory information system and at times reduces his product losses, environmental hazards, and clean-up
or her effectiveness and results in operational errors cost associated with it.
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516 Petroleum Refining and Natural Gas Processing

20.5.2.4 Operating Costs Table 20.7 shows a typical distribution of movement

In addition to economic loss to a plant from the problem tasks in a 300-kbbl/day refinery and indicates that most
areas discussed in earlier sections, a plant may also incur prominent movement tasks are tank to tank, unit to tank,
an increase in operating cost due to the following factors: and tank to truck (terminal operations), composing approx-
• Large plant inventory: In the absence of any on-line imately 56 % of the total tasks.
and timely information of availability of raw material Agrawal (1996) reported that 40–45 % of the tasks in
and finished products, plant resorts to having a large Table 20.7 take place in the fuel blending areas mostly for
plant inventory. Storage cost, unnecessary movement tank-to-tank transfers [11]. Also, it is interesting to note
of products, not being able to respond to all market that only 3–5 % of the tasks occur on a daily basis and rest
demands and fluctuation are some of the factors attrib- on slower frequencies, as shown in Figure 20.19.
uting to increased operating cost. Agrawal (1996) concluded that for a typical refinery,
• Underutilized tank capacities: OM&S operators at times the following facts can be drawn from data analysis of
tend to fill tanks at levels lower their maximum due OM&S operations [11]:
to fear of tank spills and failure of alarm. This results • Major OM&S activities: Typically, 75 % of OM&S activi-
in under utilization of tank capacities and increase in ties in a refinery are tank to tank, unit to tank, tank to
operating cost as enough raw material and/or product truck, and tank to ship.
may not be available for manufacturing or shipment. • Major refinery areas with most OM&S tasks: Typically,
• Wasted energy: This is from the electric utility cost aromatic, crude oil, gas oil, and gasoline and truck
increase as the transfers are repeated because of human terminals have the most OM&S activities.
error or from execution of avoidable transfer activities. • Task occurrence frequency: Typically, 45–50 % of OM&S
• Demurrage charges: This is quite a substantial loss to tasks occur less than once every 2 months and the
the refinery in terms of demurrage charges payable to remaining occur more than once every two months.
shipping companies because of delays in marine load-
ing and unloading and because ships must wait at port 20.5.3.1 Estimation of Automation
longer than necessary. Incentives
• Large manpower: Manual operations of opening and Agrawal (1996) categorized the estimation of benefits
closing of valves and pump start/stop sequences require into two categories: tangible and intangible benefits [11].
many field operators for the transfer activities. In addi- Tangible benefits are actually estimated using the OM&S
tion, more maintenance personnel are needed to main- operation data. Intangible benefits are only good estimates
tain the field equipment to repair them in time. of indirect incentives from the modernization of OM&S
• Improper and untimely reports: Lack of any automa- operations. Typically, potential OM&S benefits areas are
tion and implementation of information system or • Product contamination,
both may not provide inventory reports in a timely and • Quality/quantity giveaway,
accurate fashion for the day-to-day planning cycle of • Demurrage (marine operations),
the refinery operation. • Batch product blending (other than inline product
Most of the problems in the areas discussed in previ- blending),
ous sections can be eliminated or reduced by implementing
computer automation of OM&S. However, before imple- Table 20.7—Typical Distribution of OM&S
menting an OM&S automation project, a first step would be Tasks in a 300-kbbl/day Refinery
actually analyzing the OM&S operational data.
No. Transfer Task Daily Number Percent of Total

1 Pipeline to tank 4 4.6

20.5.3 Operational Data Analysis
2 Pipeline to unit 1 1.1
A refinery typically performs approximately 80–120 move-
ment tasks on a daily basis. These tasks have various com- 3 Recirculation 4 4.0
binations of sources and destinations and vary in execution
4 Ship to tank 3 3.4
frequency and duration. Agrawal (1996) pointed out that
a benefit study must establish the basis to recognize the 5 Tank to pipeline 4 4.3
estimated benefits from automation of OM&S and this is
6 Tank to ship 8 9.4
done by analyzing the operational data for a specific pro-
cess unit or an entire area’s operations [11]. The period for 7 Tank to tank 24 26.8
such operational data must be between 4 and 12 months. In 8 Tank to truck 12 13.1
the case of offsite operations in a refinery, it is necessary to
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

collect the following information for each OM&S task for a 9 Tank to unit 2 2.7
period of a minimum of 4 months: 10 Truck to tank 1 1.3
• Identification number;
• Start date, end date, and time; 11 Unit to pipeline 2 2.2
• Source/destination identification; 12 Unit to ship 1 1.1
• Source/product name;
13 Unit to tank 20 22.4
• Initial/final levels of source;
• Initial/final levels of destination; 14 Unit to unit 3 3.7
• Initial/final and total quantity transferred; and
91 100
• Planned volume or weight for transfer.
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Chapter 20 n Tank Farm Management 517

3% 3%
4%
24 %
14 %

Every Day
2 Days
3 Days
Weekly
2 Weeks
Monthly
2 Months
4 Months
13 % 14 %

25 %

Figure 20.19—Percentage distribution of task occurrence frequencies.

• Crude blending, and QLG$ = yearly benefits due to quality giveaway,

• Manpower reduction. QNG$ = yearly benefits due to quantity giveaway,
The following typical OM&S tasks are responsible for ENG$ = yearly benefits due to increase in energy consump-
the possible cause of errors and their direct/indirect effects tion, and
on the lost benefits. LOP$ = yearly benefits due to loss in opportunity.
• Line-up of movements, The above terms are defined as follows:
• Drainage of water,
• Planning of movement schedules, and MPL$ = ( number of incidents/year)
• Loading/unloading of products/feeds. × (lost man-hours/incident) × (cost, $/man-hour),
Potential benefits areas and their sources must be (20.16)
cross-linked with respect to the following contributing
parameters as shown in Table 20.8 for line-up of movement.
• Manpower,
Table 20.8—Matrix of Source of Benefits
• Demurrage,
with Contributing Parameters of Line-Up of
• Quality giveaway,
Movements
• Quantity giveaway,
• Increased energy consumption, and Sources of Benefits Contributing
• Loss of opportunity. Parameters

1 2 3 4 5 6
20.5.3.2 Benefits Model Equation
Agrawal (1996) outlined a calculation model for the cal- 1. Line-up errors
culation of benefits contributed from various parameters - Product degradation
discussed in Section 20.5.3.1 [11]. Each of the following
equations can be applied to each and every cause of the lost - Product to slop (or crude tanks)
benefits. For example, loss in tangible benefits from each - Spills
incident of product degradation caused by line-up error
- Custody transfer inaccuracies
can be attributed to losses from manpower, loss of oppor-
tunity, increased energy consumption (due to reprocessing), 2. Displacement of line material
demurrage, etc. Therefore, ”incident” would be “product
- Quality giveaway due to product
degradation due to line-up error” in the following model upgrading
equations. Also, all parameters do not necessarily contrib-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

ute to all tangible OM&S benefits. - Product contamination

3. Reduction in line-up time due to

Total benefits ($/year) = M
PL$ + DEM$ + QLG$ automation
+ QNG$ + ENG$ + LOP$ (20.15)
- Inline blending
where: - Batch blending
MPL$ = yearly benefits due to loss of manpower,
- Other products/crudes
DEM$ = yearly benefits due to demurrage,
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518 Petroleum Refining and Natural Gas Processing

DEM$ = ( number of delayed ships/year) keep the benefits of the two separate to justify an OM&S
× (average hours of delays/ship) project.
× (cost of demurrage, $/hour), (20.17) The payback period for the automation of an OM&S
project alone is 3–4 years. However, it is more beneficial to
QLG$ = ( number of incidents/year) consider an OM&S automation project along with blending
× (quantity of material, m3/incident) automation, and this has a quicker payback period. In the
× (difference in quality giveaway) author’s experience, it is very difficult to economically jus-
× (cost of quality giveaway, tify a project for the automation of OM&S after a blending
$/quality giveaway m3), (20.18) automation has already been implemented.
QNG$ = ( number of incidents/year)
× (Δ quantity giveaway, m3/incident) 20.5.4 Automation Strategy
× (cost of material, $/m3), (20.19) The automation of an OM&S operation requires that the
computer system respond to the needs of the operator to
ENG$ = ( number of incidents/year)
perform the major functions discussed in Section 20.5.4.1.
× (Δ increase in energy, kWh/incident)
× (cost of energy, $/kWh), and (20.20)
20.5.4.1 Functionality

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
LOP$ = ( number of incidents/year) • Use remote readings from tank gages to
× (Δ profit from sale of cargo/incident) (20.21) • Calculate inventories, conditional events, and total
volumes shipped.
Table 20.9 summarizes the typical range of tangible • Monitor tanks for improper movements and alarm
and intangible benefits from OM&S operations in a typical on high or low levels.
refinery of 300 kbbl/day [11]. • Respond to field element status:
It may seem that quality giveaway and product con- • Monitor remotely operated valves (ROVs), pumps,
tamination is low in Table 20.9 for the specific refinery and mixers for alarm conditions and proper
considered. Product contamination only occurs in oil response operator requests.
movement line-up errors, whereas quality giveaway largely • Keep a list of out-of-service equipment.
occurs in blending operations. Table 20.9 only considers all • Provide status information to operator.
benefits for oil movement operations and not blending to • Monitor and control movements for receipts, run-
downs, transfers, and shipments.
• Select equipment (tanks, valves, pumps, etc.) for move-
Table 20.9—Summary of Typical Benefits ments required in the schedule.
from OM&S Automation • Automatically sequence equipment to implement and
terminate movements.
Typical Benefits,
• Terminate movements, swing tanks, start other move-
Thousand
Benefit Area Dollars/Year ments, etc., when specified conditions are met.
• Provide interfaces between DCS and supervisory-level
Quality giveaway 40–50 controls of inline blenders and equipment sequencing,
Product contamination 4–6 movement monitoring, and customer’s blend control
strategy programs.
Demurrage cost reduction 400–600 • Provide summary reports and movement logs and pro-
Quantity giveaway by measurement errors 500-700 files that are defined by the customer.
• Use networked computers to receive operating data
Reducing or eliminating OM&S tasks 400–600
and to transmit historical data.
Increasing tank utilization 500–600 The above characteristics of a well designed and devel-
oped OM&S computer system provide interfaces and inter-
Integration of OM&S with computer 300–500
action among all activities of the OM&S operations in a
applications
refinery. Figure 20.20 shows the flow of information among
Increasing crude throughput by crude blending 2400–3000 OM&S activities and an OM&S computer system.
Planning and scheduling of ship unloading 200–300
20.5.4.2 Levels of OM&S Control Functions
Crude feed quality control and monitoring 200–300
The functionality of an automated OM&S system can be
Minimization of spill and leakage 95–140 translated into various control levels, as shown in Figure
Line-up errors and illegal movements 50–315
20.20:
• Level 0: This is the lowest level at which all field equip-
Minimization of product loss in water 25–40 ment such as pumps, ROVs, mixers, and control valves
drainage are controlled by the electronic system. Tank levels and
Better utilization of OM&S equipment 60–155 temperature are also monitored at this level.
• Level 1: This level is called the supervisor control in
Better planning and scheduling 60–100 which computer systems monitor the status of process
Manpower reduction 40–1250 variables or field equipment or send the command for
remote control operation. For example, instead of start-
Total typical OM&S benefits 5000–8500
ing or stopping a pump from the field or remote panel,
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Chapter 20 n Tank Farm Management 519

DISPATCH
RECEIVE ORDERS, SET
SETUP
UPTASKS,
TASKS, LEVEL-3
ISSUE DOCUMENTS

BLENDING TASK CONTROL

DEFINE, SETUP, CONTROL, DEFINE, SETUP, CONTROL, LEVEL-2
MONITOR, LOG, REPORT- MONITOR, LOG, REPORT-
BLENDING OPERATIONS MOVEMENT OPERATIONS

MONITORING REMOTE OPERATION

READ, ALARM, CONTROL, LEVEL-1
READ, ALARM, MONITOR, MONITOR, LOG, REPORT -
LOG, REPORT - TANKS BI-STATE ELEMENTS

LEVEL TEMP. PUMP MOV MIXER CONT. LEVEL-0

TANK

Figure 20.20—Control levels of oil movement system. Source: [10].

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

the operator could issue a command from the computer • Path selection,
to operate a valve or pump. Tank gaging systems such • Sequence generation, and
as Wesson, Varec, Enraf, and Saab provide computer • Sequence control.
interfaces to monitor the tank levels and temperatures. We shall walk through an example of an OM&S task
• Level 2: This level involves extensive application pro- with all of these steps, along with representative displays,
gramming and offers the maximal benefits of auto- to illustrate how an OM&S operator would use an OM&S
mation. Various steps of executing an OM&S activity computer system to perform his daily transfer activities.
are automated at these levels and are categorized into Figure 20.21 shows the functional modules of a typical
separate modules such as task definition, sequence OM&S system.
generator and control, task monitor, etc. Blending is
also implemented at this level. 20.5.4.3.2 Selection of Activity Type
• Level 3: This is the topmost level and is usually termed This is the first step for the operator to select the type of
as the information system level. Information about transfer activity he wants to execute by choosing a task
various refinery activities such as planning, scheduling, type from the menu. The operator can select the task type
shipping, and dispatching is collected at this level and is or enter the task identification number (ID) if he knows it
interfaced with OM&S control modules for overall inte- already.
gration of the system.
20.5.4.3.3 Task Definition
After selecting the activity type, tank-to-tank transfer in
20.5.4.3 Categories of OM&S Control
Figure 20.21, the next step is the task definition step. This
Functions
step requires three inputs: source, destination, and stop
From a simplistic view of OM&S control functions, they
condition or size of transfer. Because the task database has
can be divided into three basic categories:
other information such as material, pump ID, and task ID,
1. What must be done?
this information is shown only upon entry of source and
2. What is going on now?
destination. The operator can also enter the task ID if he
3. What has happened?
already knows this information. The operator can always
In the next sections, we will discuss that almost all
override the inferred data shown by the system with valid
functionality of an OM&S computer belongs to a category
entries.
answering one of these three questions.
20.5.4.3.4 Path Selection
20.5.4.3.1 Steps to Execute an OM&S Activity The next step of task implementation is the selection of
The following steps to execute an OM&S activity are valid a path through the refinery network. The path selected is
regardless of their automation; that is, the operator goes governed by two specifications: the data defined for the
through these steps even in manual operations. task and the path/network database. A path for a specified
• Selection of activity type, task can be defined in one of two ways: the predefined
• Task definition, or “canned” path or the dynamic and optimal path. The
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520 Petroleum Refining and Natural Gas Processing

CENTRAL DATABASE
TASK
TASK DATA
DEFINITION
TASK
DEFINITION
TASK MONITOR SEQUENCE STATUS
MODULE
TASK REQ.
TASK TANK
REQUEST STATUS

TANK MONITOR TASK CONTROL

MODULE MODULE

Figure 20.21—Functional modules of an oil movement control system. Source [12].

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

approach followed for a given refinery depends on the 20.5.4.3.5 Sequence Generation
complexity of the network and the number of task types. After the path is selected and approved by the operator, a
The canned path algorithm is not very flexible compared sequence of operating the field equipment needs to be gen-
with the dynamic path algorithm, but it takes less resources erated. This sequence consists of field equipment for the
and is more efficient. In short, the dynamic path algorithm isolation of path and for flow path and startup (i.e., pump)
is recommended for a very complex and interactive net- of the task. Each piece of field equipment in this sequence
work of field equipment. of operations has a relevant action (of valve close or open)
The path selected for the specified task is displayed and its own individual modes of operation (i.e., manual,
in two ways—tabular and graphical formats—as shown in automatic or required operator initiation). This is shown
Figure 20.22. in Figure 20.23.

Figure 20.22—Path selection of an oil movement control system. Source: [13].

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Chapter 20 n Tank Farm Management 521

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 20.23—Sequence generation of an oil movement control system. Source: [12].

20.5.4.3.6 Task Status Monitoring 20.5.6 Project Implementation

After the OM&S task is implemented, the operator can A typical OM&S automation project takes 18-24 months
monitor the status of tasks in several ways, each displaying from start to finish. Table 20.10 shows a typical list of proj-
information from different perspectives. The task monitor ect activities and a project timeline to give readers an idea
status can be displayed as follows: of what is involved in an OM&S automation project. Actual
• Status of single task; details, duration, and activities may vary from refinery to
• Status of all tasks (active, defined, scheduled, commit- refinery depending on the project size and the allocated
ted, unassigned, etc.); funds for the project.
• Status of a group of tasks such as all those related to
gasoline activities; and 20.6 Terminal Operations
• Screen report of tank inventory, which can again be Terminal operations handle crude/product receipts and
grouped by products or area or tanks. product dispatch at marine, truck, railcar or wagon, and
pipeline terminals, with each one having their own charac-
20.5.5 Integrated OM&S System teristics from an operational point of view as well as their
The components of an integrated OM&S computer system own problems and challenges. Nevertheless, they all have
depend on the status of automation, the refinery informa- the inherent problems and challenges of following custody
tion system in a particular refinery, and the computing transfer issues.
platforms of the OM&S system. For example, some com- • Custody transfer is the reconciliation of accounting
mercially available OM&S systems include blending as one of the amount of refinery feed or product exchanged
of the modules. The OM&S algorithm as such does not between the refinery and an external party (buyer or
include any linear programming (LP) algorithm, whereas seller).
the inline blending uses either LP or the nonlinear equa- • The custody transfer error for crude oil receipts alone
tion solver and optimization using nonlinear blend models can cost a 300-kbbl/day refinery approximately $15–30
depending on the type of product blend. In addition to million (U.S.)/year on the basis of the assumption of a
this, a truly integrated OM&S system must interface with crude price of $50 (U.S.)/bbl and a best measurement
the refinery’s information management system for history, accuracy of ±0.25-0.50 %.
databases, reports, reconciliation, etc. This results in the • This can affect the bottom line by as much as 5–10 %
customized integration of an OM&S system for each refin- on the basis of the assumption of a refinery profit mar-
ery and may involve developing many interfaces for various gin of $2/bbl or less.
modules and computers. Figure 20.24 shows a diagram • Accurate measurement and accounting for water con-
for the integration of an OM&S system with refinery-wide tent in crude oil receipts can save further to avoid pay-
planning and other applications. ing for water at crude oil prices.
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522 Petroleum Refining and Natural Gas Processing

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 20.24—Integration of OM&S system with refinery-wide planning and scheduling system.

Table 20.10—Tentative Project Execution Plan

Elapsed Months

Activity 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

Project start •

Site survey and project design

basis

Definition of tasks and path

line-up

Application design basis

Interface development/testing

Application design and

development

Customization of application

Order of computer systems

Application commissioning

Interface commissioning

Training and startup

Project completion •

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Chapter 20 n Tank Farm Management 523

• Delayed reconciliation and documentation results in periods of time and the scheduled wagons are less frequent
transfer disputes between supplier and refinery and a than truck terminals on a daily basis.
loss of revenues.
Figure 20.25 enumerates the challenge severity matrix 20.6.4 Pipeline Terminals
of all terminal operations and indicates that marine and Pipeline terminal challenges are as follows:
pipeline terminals pose the most challenges compared with • They are the most difficult to manage because of distance.
trucks and railcar terminal operations. • They need elaborate equipment (pumping stations) to
send material over varying heights.
20.6.1 Truck Terminals • Leaks may disrupt the service and cause safety hazards.
Truck terminal operations face the following challenges: • Product contamination.
• They require efficient planning and scheduling of • They involve multiple enterprises and vendors.
100–300 trucks/day. • They require robust control systems and sophisticated
• Tank compartments are manually gaged, leaving room remote monitoring instruments.
for custody transfer discrepancies.
• Human errors can cause product contamination in 20.7 Blending
truck compartments. Blending can be defined as a process of homogenous mix-
• Requires a minimum of 1 week of planning of product ing of two or more ingredients to produce a product with
inventory to schedule incoming trucks. certain desirable qualities or attributes. The objectives of
• The trucks queues must be coordinated efficiently. blending are
Figure 20.26 shows an example of truck terminal • The final product qualities must never violate the speci-
operation. fied qualities or attributes.
• The final product must be produced with minimal cost
20.6.2 Marine Terminals or maximal profit.
The challenges of marine terminal operations are The examples of blending in any liquid- or solid-based
• Planning and scheduling, plant are shown in Table 20.11.
• Demurrage charges, The blending operations in any industry are considered
• Accurate flow measurement, important because
• Flow meter proving, • Sources for the product ingredients are becoming
• Water content analysis, scarce and varying in qualities. For example, in the
• Crude oil sampling point location, upstream refining industry, exploration of crude oil
• Representative sampling of crude oil, and from offshore and onshore sources leads to varying
• Sampling system proving. crude quality and quantity.
• End-users are demanding more stringent product qual-
20.6.3 Railcar Terminals ities. Technological advances in the end-user industry
Railcar terminal operations are similar in operations to (e.g., automobile industry) are demanding efficient and
the truck terminals. However, their activities are for longer low-emission fuels.

Challenge Severity Matrix

Marine Trucks / Railcar Pipeline

• Demurrage Charges High None None

• Opportunity loss due to
High Small High
product unavailability
• Quantity giveaway due High Small High
to faulty meters
• Product degradation Small Negligible High

• Contamination Small Negligible Medium

• Lack of proper scheduling
of resources and products High Medium High

shipment or feed receipts

• In-time billings High Small Small

• Improper feed / products

High Negligible High
preparation due to lack of tanks
• Custody transfer reconciliation High Small High
errors
Figure 20.25—Challenge severity matrix of terminal operations. Source: [1].
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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524 Petroleum Refining and Natural Gas Processing

Tanks Farm Tanks Farm

Product-A Product

Tanks Farm
Trucks
Product -C
Lined-Up Queue

Pumps House

Trucks Loading Racks

Control Room
Trucks Queue Area

S & D Office
Exit
Entry

Figure 20.26—Example of truck terminal operation in a typical refinery. Source: [1].

• Strict government regulations on product qualities. These objectives can be achieved by the following feed
• Competitive business environment to minimize the and product quality-control systems:
cost of production. Crude oil refiners are getting com- • Feed quality control
plex in their conversion processes to maximize prod- • Marine planning and scheduling
ucts from a barrel of oil yet be able to process crude of • Movement task monitor and control
varying qualities. • Crude tank composition, monitoring, and optimi-
• Environmental concerns and regulations restrict the zation
method of production. • Product quality control
In this section, we will discuss some of the blending • Crude unit model
applications in refining and petrochemical complexes to • Crude unit LP optimizer
give the reader an idea of the complexity involved in blend- • Product blending optimizer
ing operations. Figure 20.27 shows a schematic diagram to integrate
all systems required to control the quality of crude feed to
20.7.1 Crude Blending
The main objectives of a crude unit in a refinery are to
optimize the quality and yields of cuts and operate the
unit in a stable and safe manner. It is important that crude Table 20.11—Example of Blending in the
feed to a unit has uniform quality and availability. This is Manufacturing Industry
becoming difficult on a day-by-day basis for the refiners to
Industry Blending Operation
obtain enough crude with consistent quality economically
from one source of supply. It is therefore important to blend Refining Crude, gasoline, diesel, fuel, lube oils
crudes from different sources with varying qualities to feed Petrochemical Naphtha
to the crude unit with crude of consistent quality. There-
fore, the objectives of crude blending are Power generation Coal blending
• Minimization of dependency on crude feed quality for Cement Kiln feed blending
stable and optimal operation,
• Maximization of product yields and quality, Paper and pulp Pulp and fiber blending
• Improve crude oil inventory for “just-in-time” manu- Steel manufacturing Blast furnace feed
facturing, and
• Reduction in demurrage by better planning. Food and Beverage Various food items
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Chapter 20 n Tank Farm Management 525
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 20.27—Integrated crude feed quality-control systems.

the crude unit. The main qualities controlled are density, author in Chapter 19 and hence will not be discussed here
sulfur, and water content in the crude feed [14]. to avoid duplication of topics.
Crude can be blended in any of the following modes:
• “Pipelines-to-tanks” blending, 20.7.3 Lube Oil Blending
• “Ships-to-tanks” blending, Lube blending is very different than crude blending or fuel
• “Tanks-to-tanks” blending, and blending. Lube blending is characterized by 300–400 types
• “Tanks-to-units” blending. of finished products with smaller batches of 15–25 bbl.
Crude blending can be very complex if the crude supply On the other hand, fuel blending produces 10–15 types of
is via pipelines, and their source, types, and qualities vary grades with 50,000- to 100,000-bbl batch size. Crude blend-
extensively. Crudes from pipelines can be stored in tanks ing batch size could be approximately 100–300 bbl. Lube
keeping their individuality, or they can be blended partly in blending also has a risk of contamination leading to sending
the tanks to achieve uniform qualities for a particular type the batch to burners and loss of revenue. Inline blending
of crude (e.g., light crude, heavy crude, low- or high-sulfur for the lube plant is economical for plants producing more
crude, paraffinic or naphthenic crude, etc.). Figure 20.28 than 150,000 bbl/year. There are two methods of inline lube
shows an example of a crude blending configuration receiv- blending:
ing crude via pipelines and two-stage blending to prepare 1. Stationery batch tanks: In this mode, the batch hold-
specific crude unit mixes. ing tanks remain stationery and can meet product
The crude mixes are thus prepared and then again demands rather quickly. On the down side, the mode
blended to a specific crude unit’s requirements using multi- requires a great deal of pipe and instrumentation to
tank and multiheader blending configurations as shown in control the batch quality (see Figures 20.30 and 20.31).
Figure 20.29. In this design configuration, crude mixes are 2. Moving batch tanks: This mode keeps the batch tanks
blended into six crude feed tanks for six crude units. Each of moving and as they pass the filling stations, recipe
the crude units is designed to process only one type of crude. components are blended. The mode requires less
Agrawal (1994) presented a design view to integrate manpower, piping, and valves and it has better quality
crude blending feed-forward strategy with product blend- controls (see Figure 20.32).
ing feedback strategy to optimize crude and product quali-
ties [14]. To the author’s knowledge there is no commercial 20.7.4 Naphtha Blending
system available as an integrated system for the overall Naphtha is a byproduct of crude distillation, and its boil-
optimization, but the idea and its feasibility still exists. This ing point is between 30 and 200°C. It consists of a com-
is shown in Figure 20.29. plex mixture of hydrocarbon molecules generally having
between 5 and 12 carbon atoms. It typically constitutes
20.7.2 Fuel Blending 15–30 % of crude oil, by weight. Light naphtha is the
The blending of gasoline, diesel, and fuel oils is termed fraction boiling between 30 and 90°C and consists of mol-
“fuel blending.” Fuel blending is covered extensively by the ecules with five to six carbon atoms. Heavy naphtha boils
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526 Petroleum Refining and Natural Gas Processing

Figure 20.28—Typical example of pipelines-to-tanks crude blending.

Figure 20.29—Multiheader crude blending.

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Chapter 20 n Tank Farm Management 527

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Figure 20.30—Integrated crude and product blending and optimization strategy.

DEHYDRATOR

BULK
DELIVERY
IN-LINE
BLENDERS
BASE COMPONENTS

HOLDING TANKS

BATCH
BLENDING

ADDITIVE
STORAGE
PACKAGIING

BASE
FILLING &

OILS IN STORAGE
&
ADDITIVE DISPATCH
LIQUID DUMP &
ADDITIVES IN DILUTION

(SEMI) ADDITIVE DRUM

HEATER
SOLIDS IN

Figure 20.31—Stationary tank lube inline blending. Source: [15].

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528 Petroleum Refining and Natural Gas Processing

Operator Controller Plant

console computer

Printer

Manual Filling Mixing/heating Transfer

inspection vessel station station station
identification Weighing & To hold for
Compatibility selection PD metering analysis
or reject for discharge
cleaning/flushing

Transport Transport Transport

Robot or conveyor

Figure 20.32—Moving tank lube blending. Source: [15].

between 90 and 200°C and consists of molecules with 6–12 Naphtha blending is needed for ethylene manufactur-
carbons [15]. ing and it requires precise control of density and PIONA.
Naphtha is used primarily as feedstock for producing In a typical naphtha blending strategy, naphtha from
high-octane gasoline (via the catalytic reforming process). different sources are blended into tanks as shown in Fig-
It is also used in the petrochemical industry for producing ure 20.33.
ethylene. Natural cut naphtha can have 100 or more compo- The next stage of naphtha blending takes the naph-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

nents and requires characterization based on boiling range; tha tanks as blended in stage 1 and the blends into tanks
density; and content of paraffins (n-alkanes), isoalkanes, ole- feeding to olefin cracking units as shown in Figure
fins, naphthenes, and aromatics (PIONA) by carbon number. 20.34.

Figure 20.33—Stage 1 naphtha blending from supply sources to tanks. Source: [1].
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Chapter 20 n Tank Farm Management 529

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Figure 20.34—Stage 2 naphtha blending from blended naphtha tanks to feed tanks. Source: [1].

20.8 Summary [7] Agrawal, S.S., “Advances in Tank Quality Measurements Can
Help Cut Operational Costs,” Hydrocarbon Process., Vol. 86,
This chapter has briefly but adequately discussed all
2007, p. 67.
aspects of tank farm management. Some of the topics could [8] Agrawal, S.S., Leong, K.M., Wee, L.H., and James, C.T.J.,
not be discussed in detail because of space limitation, but “Implementation and Benefits of Online Tanks Quality Track-
the author has made an effort to present the reader with ing System in a Singapore Refinery,” Hydrocarbon Asia, Vol.
an overview of tank farm management. The reader should 15, 2005, p. 36.
follow the literature and online resources for more specific [9] “TANKS Emissions Estimation Software, Version 4.09D,”
http://www.epa.gov/ttnchie1/software/tanks/index.html.
details about any of the topics presented in this chapter.
[10] “Emissions Factors & AP 42, Compilation of Air Pollutant Emis-
sion Factors,” http://www.epa.gov/ttn/chief/ap42/index.html.
[11] Agrawal, S.S., “Economics Justifications of an Integrated
References Oil Movement & Storage Control System,” presented at the
[1] Offsite Management Systems, LLC (OMSLLC), Training Man- ISA’96 Conference and Exhibit, Chicago, IL, October 9–12,
ual, OMSLLC, Sugar Land, TX, 2009. 1996.
[2] Nelson, W.L., “What Is Adequate Storage Capacity?,” Oil & Gas [12] “Oil Movement and Storage,” (sales brochure), Honeywell,
J., September 7, 1959, p. 184. Inc., Morristown, NJ.
[3] Nelson, W.L., “How Much Refinery Storage?,” Oil & Gas J., [13] Agrawal, S.S., “Scope of an Integrated Oil Movement and
April 23, 1973, p. 88. Storage (OM&S) Control System,” Proceedings of ISA Confer-
[4] Gary, J.H., and Handwerk, G.E., Petroleum Refining- ence, New Orleans, LA, October, 1995.
Technology and Economics, Marcel Dekker, New York, 1994, [14] Agrawal, S.S., “Scope and Feasibility of Integrated Crude
pp. 354–355. Blending Control and Optimization System,” presented at the
[5] Barsamian, J.A., and Whitehead R., “Statistical Method ISA’94 Conference and Exhibit, Philadelphia, PA, May 9–12,
Used to Estimate Refining Tankage,” Oil & Gas J., February, 1994.
2000. [15] Lube Oil Blending—An Overview for Lube Plants, http://
[6] Al-Otaib, G., and Stewart, M., “Simulation Model Determines www.jiskoot.com/downloads/TB008%20-%20Lube%20Oil%20
Optimal Tank Farm Design,” Oil & Gas J., February, 2004. Blending.pdf.

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21
Refinery Planning and Scheduling
Nan Zhang1 and Marc Valleur2

21.1 Introduction closely monitor their performances, adjust their opera-

To construct an optimization problem in mathematics, tions correspondingly, identify their key weaknesses, and
there are three main elements: variables, an objective func- correct them promptly. Although these principles are easy
tion, and process model/constraints. Optimization variables to understand, achieving them is very difficult. There are
are always involved in tradeoffs to seek the best objective so many decisions involved to achieve the optimal opera-
value, with their changes bringing a certain impact on the tion for a refinery. From the managerial level, managers
objective value. Optimization variables can be either con- need to decide which crudes to process, which products to
tinuous or discrete in nature and therefore can be classi- produce, which operating route to follow, which catalyst
fied as continuous variables and integer variables. There is to use, which operating mode to choose for each process,
a special subclass of integer variables—binary variables. A etc. From the process level, operators have to determine
binary variable can take either 0 or 1 and is very useful to detailed operating conditions for each piece of equipment,
model some discrete conditions such as on/off, yes/no, etc. such as temperatures, pressures, detailed process flows, etc.
The objective function is expressed in terms of optimi- All of the decisions interact with each other. For example,
zation variables. The goal of optimization is then to find the temperature change in a reactor will result in different
values of all of the variables that yield the optimal value of product distribution and utility consumption, hence dif-
the objective function, which can either be minimization or ferent process performance. It may further affect the deci-
maximization of a real function. sions at the managerial level in terms of feed selection for
Depending on the nature and scope of the optimization this process and even overall plant operating route. A cycle
problem, process model/constraints arise from kinetics; of operations [1] has been formed in the refining industry
thermodynamics; mass and energy balance; and physical to achieve profitable manufacturing by producing quality
bounds on variables, physical laws, empirical correlations, products under a safe operating environment (Figure 21.1).
etc. These constraints are in the form of either equalities or The cycle starts with central planning to determine
inequalities. long- and mid-term operations. Scheduling then deals with
The whole set of equalities and inequalities plus short-term day-to-day operations. Advanced control and
the objective function constitutes an optimization model, online optimization translate the goals set by planning and
which describes the interrelationships among all optimiza- scheduling to real-time process targets, which are executed
tion variables. The general formulation of an optimization by regulatory control. Monitoring and analyzing the results
problem can be summarized as follows: provide feedbacks to the initial decision-making procedure.
The cycle is completed with overall refinery optimization, the
Maximize (or minimize) f(x, y) task of which is to find the best combination of those deci-
subject to: h(x, y) = 0 sions to maximize the overall profit. Because overall refinery
g(x, y) ≤ 0 optimization almost covers all of the aspects relating to
x, y ≥ 0 profit-making refinery operations, it is therefore considered
where: one of the most difficult and challenging optimization tasks.
x is a set of continuous variables and y is a set of integer Refinery optimization is to push operation toward the
variables. maximal profit until it reaches the limit. Once the profit
limit is reached, the only way to further increase profit is
21.2 The Problem of Refinery to make some changes to the existing plant. For an exist-
Optimization and Debottlenecking ing plant, especially when it has been in operation for a
Oil refining is one of the most complex chemical industries considerable period of time, more and more shortcomings
and involves many different and complicated processes emerge, largely because of the change of market situation
with various possible connections. The task of refinery and the evolution of science and technology. For example,
operation is to generate profit as much as possible by con- an existing plant does not have enough throughputs to
verting crude oils into valuable products such as gasoline, meet current and future market demand, it cannot satisfy
jet fuel, diesel, and so on. Refineries are currently facing new environmental regulations, it consumes too much
stiff competition under more and tighter environmental energy, it does not have sufficient reliability, etc. Spending
regulations. The most successful refineries are those that major capital to build new units can directly solve those
1
The University of Manchester, Manchester, UK
2
VAL Innovation Consulting, Le Chesnay, France
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531
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532 Petroleum Refining and Natural Gas Processing

Planning y

Reality

Analysis Scheduling

Recursion

Monitoring Advanced control Conventional LP

and optimisation

Regulatory x
control
Figure 21.2— Comparison between conventional LPs and
Figure 21.1—The cycle of refining operations. recursions.

approximation for many processes with nonlinear natures.

problems. But more often, revamping (debottlenecking) the As a result, this kind of model cannot accurately describe
existing plant is a more attractive option because an exist- the nonlinear aspects.
ing plant can usually be modified more quickly with less To mimic nonlinear behavior while maintaining linear
capital and risks than installing a new unit. To remain com- formulation, recursion techniques in LP are commonly
petitive, oil refineries are constantly searching for potential used, which require sequential execution of several LPs.
debottlenecking opportunities to improve their operations. The solution from the current LP is used as a starting point
for the next LP (Figure 21.2).
21.3 Mathematical Methods Although recursion gives more accurate solutions, it
In mathematical terms, an optimization problem in oil not only increases computing time, but it also reduces the
refineries can be expressed as objective function: transparency of LP’s value structure and its economic driv-
ing forces and therefore reduces users’ confidence [3].
Maximize profit = product sale – material cost – operating cost In general, because of the simplistic nature of LP, LP
approaches are restricted to long- and medium-term plan-
or ning for plant-wide optimization and are not suitable for
day-to-day and real-time operations.
Minimize cost = operating cost + material cost
21.3.2 NLP-Based Methods
subject to: The refinery optimization problem is nonlinear in nature,
• Process operations (e.g., kinetics, temperatures, pres- and people have been trying to solve such problems as they
sures, flow rates); are, with some success, especially in local operations such
• Process connections; as individual refining processes and blending operation.
• Various limitations (e.g., throughput, product specifica- Furthermore, Aspen PIMS® Advanced Optimization (Aspen
tions, market demand, and environmental regulations); PIMS-AO) is a commercial package that allows certain non-
• Resource utilization (e.g., power, steam, and hydrogen). linear features to be solved as a part of the overall refinery
This mathematical formulation can be generally clas- model. However, Aspen PIMS-AO cannot be considered as a
sified as linear programming (LP) and nonlinear program- solution for rigorous overall refinery optimization. In theory,
ming (NLP). If all of the objective functions and constraints a rigorous NLP model for overall plant operation could be
are in linear form, it is LP formulation. If any of them are formulated by lumping all of the rigorous process models
nonlinear, it is NLP formulation. Because of the economic together. However, to date, there is no commercial NLP soft-
significance and strong competition, oil companies tend to ware available for rigorous overall refinery optimization. Even
develop and maintain LP models in-house and there are suppose that we had such an NLP model built, we would have
very few publications available to the general public. great difficulties in mathematics and computation to solve
such a complex overall plant model [4]. Therefore, layered
21.3.1 Linear Programming-Based Methods approaches have been developed [5,6] to overcome such dif-
By assuming complete segregation between defined ele- ficulties. Aspen PIMS-SC® also adopts similar ideas in their
ments, LP is widely used in refinery optimization. In fact, commercial applications. The essential idea is that a com-
the state of the art is to use LP or mixed integer linear pro- munication mechanism is created between different levels of
gramming (MILP) for planning purposes of overall refinery refinery optimization, with a simplified overall model on top,
operations (e.g., optimizing selections of raw materials and supported by individual process models, so that a large prob-
products). LP techniques for overall refinery optimization lem is decomposed and then solved at a relatively small scale.
are relatively mature. In the meantime, many petroleum For individual process optimizations, detailed models
companies have developed their own LP tools in-house. are typically used to optimize operating conditions, such
It is not only because of the speed and robustness of LP, as temperatures, pressures, detailed process flows, etc.
but more important, a complete value structure in terms The results from this kind of optimization are much closer
of marginal prices can be easily obtained, which provides to the reality. However, there is no proper coordination
meaningful information on solution explanation and sensi- between an overall plant LP optimization and different
tivity analysis [2]. However, LP and MILP models are built --```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
process NLP optimizations. Therefore, no guideline is
based on simplified correlations, which are just a rough provided from the overall plant optimization to process
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Chapter 21 n Refinery Planning and Scheduling 533

ptimizations, which means that individual processes are

o
optimized based on a standalone basis. Consequently, the Table 21.1—Stream Identification
synergy between plant-wide aspects and process opera- Stream Name Description of Stream in Flow Sheet
tions cannot be exploited properly, which greatly limits the
H1 Reactor outlet stream to be cooled down
economic contribution of process optimizations.
H2 Diesel stream from distillation side stripper to
21.3.2.1 Case Study be cooled down
An example of NLP (mixed integer nonlinear program- H3 Gas oil stream from reboiler to be cooled
ming, MINLP) optimization problems in oil refineries is the down
design of a heat exchanger network (HEN) for the vacuum
gas oil (VGO) hydrotreater unit of an oil refinery [7]. The C1 Reactor inlet stream to be heated to reaction
temperature
VGO hydrotreating unit takes VGO and treats and upgrades
it to more useful products. During this hydrotreating opera- C2 Stream from low-pressure separator heated to
tion, the boiling range of the feedstock is not altered sig- hydrogen sulfide stripper
nificantly. Normal hydrotreater reaction temperatures are
C3 Stream from hydrogen sulfide stripper heated
approximately 300–400ºC and the reactions are catalytic. to distillation inlet temperature
Moreover, the process of hydrotreating consumes large
amounts of hydrogen. C4 Side stripper reboiler
In the hydrotreating operation, the feed is first mixed
with the hydrogen and heated to the reactor inlet tempera-
ture. This can be done by a single furnace but is more effi- of each period by adjusting parameter DOP(p). The data
ciently done by reusing waste process heat first and using the extracted from the flowsheet are
furnace to provide the high-temperature heat. Although many • Stream inlet and outlet temperatures,
reactions take place inside of the hydrotreating units, the net • Stream-specific heats at heat exchanger inlet and out-
reaction is of exothermic nature and the reactor outlet tem- let, and
perature tends to be somewhat higher than the inlet tempera- • Stream mass flow rates.
ture. Then, the reactor effluent is cooled down and passed to a The identified streams are presented in Table 21.1.
series of flash separators to separate and recycle hydrogen for In this case, the distillation column uses steam strip-
reuse. The products are then passed through a hydrogen sul- ping in the main column and therefore does not need a
fide stripper to remove most of the hydrogen sulfide present. reboiler at this position. At higher distillation temperatures,
Finally, a series of distillation columns (simple or complex) steam stripping proves to be more beneficial than the use of
separates light hydrocarbons, gasoline, diesel, and gas oil. a reboiler in many cases.
During the duration of the hydrotreating process, the The necessary data obtained from the HYSYS simula-
catalyst used in the reactor gradually loses its activity. tion are combined in Tables 21.2, 21.3, and 21.4 represent-
Therefore, to compensate for the loss of reaction rate due ing periods SOR, MOR, and EOR, respectively.
to loss of catalyst activity, the reactor inlet temperature is The heat capacity flow rates shown in these tables are
gradually increased. This causes not only disturbances to the average heat capacity flow rates of each stream. It is
the HEN in terms of stream inlet and outlet temperatures, possible to obtain linear or higher level polynomial func-
but also in terms of reactor outlet compositions, which are tions of Cp with respect to temperature. Constant Cp values
the result of changes in operating conditions. This change were chosen as input to the MINLP model discussed below
in composition then affects the flow rates of the diesel and to allow a robust and reasonably fast solution.
gasoline formed as well as the amount of hydrogen used This multiperiod MINLP model minimizes the total
and recycled. These changes in operating conditions give annualized cost (TAC). The costs included are capital costs
rise to the need for designing multiple period HENs that for heat exchanger area and unit and operating costs for
are not only feasible for these different conditions but can utility consumption. The match between two streams is
also provide optimal solutions for all operating conditions. denoted by a binary variable. This binary variable takes the
HYSYS simulation software was used to model the
steady-state performance of the VGO hydrotreater unit and
Table 21.2—Extracted Stream Data for SOR

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
subsequent separation units. The operating conditions and
some unknown parameters were obtained from the speci- Heat Capacity
fication of the distillate products in terms of boiling point Inlet Outlet Flow Rate F
curves. From the simplified flow sheet, the necessary hot Stream Temperature (ºC) Temperature (ºC) (kW/K)
streams (streams which need to be cooled down) and cold H1 393 60 201.6
streams (streams which need to be heated up) were identi-
fied, and the necessary stream data were collected from the H2 160 40 185.1
simulation. This simulation was repeated for three operat- H3 354 60 137.4
ing periods:
1. Start of run (SOR), C1 72 356 209.4
2. End of run (EOR), and C2 62 210 141.6
3. Middle of run (MOR), which uses the average values of
SOR and EOR. C3 220 370 176.4
These three periods are assumed to have equal dura-
C4 253 284 294.4
tions. In the model it is possible to specify the duration
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534 Petroleum Refining and Natural Gas Processing

Table 21.3—Extracted Stream Data for MOR

[ tj( j, k, p) − tj( j, k + 1, p)] ⋅ Fj( j, p)
= ∑ q(i, j, k, p), k ∈ ST, j ∈CP, p ∈PR (21.4)
Heat Capacity i∈HP
Inlet Outlet Flow Rate
Stream Temperature (ºC) Temperature (ºC) F (kW/K) At both sides of the superstructure, the variable tem-
H1 406 60 205.0
peratures need to be assigned by the inlet and outlet tem-
peratures of all streams. The inlet temperatures of the hot
H2 160 40 198.8 streams will be at temperature location k = 1, and the inlet
temperatures of the cold streams will be at temperature
H3 362 60 136.4
location k = NOK + 1.
C1 72 365 210.3
Tiin( i, p) = ti( i,1, p), i ∈HP, p ∈PR (21.5)
C2 62 210 141.0

C3 220 370 175.4 Tjin( j , p) = tj ( j, NOK + 1, p), j ∈CP, p ∈PR (21.6)

C4 250 290 318.7
To make sure that there is a monotonic decrease or increase
value of 1 if a heat exchanger exists in any of the operating in temperature from the inlet to the outlet temperature, the
periods and the value of 0 if no heat exchanger exists in any following constraints are used. Also, the temperatures at the
of the operating periods. The continuous variables to be outlet of the superstructure are limited by the stream outlet
optimized are stream temperatures for each stage and heat temperatures. If no utility exists from one given stream,
loads for each match in each period. then the outlet temperature of the superstructure equals
The constraints consist of a series of equality con- the stream outlet temperature. If utilities exist for the given
straints representing the heat balances at different levels stream, then the superstructure outlet temperature can be
and several inequality constraints for assessing feasibility either greater than the stream outlet temperature (cold util-
and defining logical operations. ity) or less than the stream outlet temperature (hot utility).
The overall stream heat balances make sure that each
stream receives the amount of heating or cooling that is ti( i, k, p) ≥ ti( i, k + 1, p), k ∈ST, i ∈HP, p ∈PR (21.7)

required for each period.

[Tiin( i, p) − Tiout( i, p)] ⋅ Fi( i, p) tj ( j , k, p) ≥ tj ( j , k + 1, p), k ∈ST, j∈CP, p ∈PR (21.8)

= ∑∑ q( i, j , k, p) + qcu( i, p), i ∈HP, p ∈PR (21.1)
k∈ST j∈CP
Tiout( i, p) ≤ ti( i, NOK + 1, p), i ∈HP, p ∈PR (21.9)

[Tjin( j, p) − Tjout( j, p)] ⋅ Fj( j, p)

Tjout( j , p) ≥ tj ( j ,1, p), j∈CP, p ∈PR (21.10)
= ∑ ∑ q( i, j, k, p) + qhu( j, p), j ∈CP, p ∈PR (21.2)
k∈ST i∈HP
To determine the temperatures at each stage, stage-wise Similar to the energy balances for the main set of heat
heat balances are necessary, which define the total amount exchangers in the superstructure body, there are energy
of heat rejected or received by a stream in any stage. balances for the utility matches, forming the relationship
between the outlet temperatures of the superstructure and

[ ti( i, k, p) − ti( i, k + 1, p)] ⋅ Fi( i, p)
the stream outlet temperatures.
= ∑ q(i, j, k, p), k ∈ST, i ∈HP, p ∈PR (21.3)
j∈CP [ ti( i, NOK + 1, p) − Tiout( i, p)] ⋅ Fi( i, p) = qcu( i, p), i ∈HP, p ∈PR
(21.11)

[Tjout( j, p) − tj( j,1, p)] ⋅ Fj( j, p) = qhu( j, p), j∈CPP, p ∈PR

Table 21.4—Extracted Stream Data for EOR (21.12)
Heat Capacity
Inlet Outlet Flow Rate The following logical constraints form the relationship
Stream Temperature (ºC) Temperature (ºC) F (kW/K) between the existence of a match, its heat load, and the
upper bound to this heat load. When a match exists, heat
H1 420 60 208.5
load q is bounded by its upper bound, and when no match
H2 160 40 175.2 exists, q is forced to zero.

H3 360 60 134.1
q( i, j , k, p) − Qup ⋅ z( i, j , k) ≤ 0, i ∈HP, j ∈CP, k ∈ST, p ∈PR
C1 72 373 211.1 (21.13)
C2 62 210 140.5
qcu( i, p) − Qup ⋅ zcu( i) ≤ 0, i ∈HP, p ∈PR (21.14)
C3 220 370 174.5

C4 249 286 271.2 qhu( j , p) − Qup ⋅ zhu( j ) ≤ 0, j ∈CP, p ∈PR

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
(21.15)
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Chapter 21 n Refinery Planning and Scheduling 535

z( i, j , k), zcu( i), zcu( j ) ∈ {0,1} (21.16) Table 21.5—Multiperiod Simultaneous

Model
To ensure feasible driving forces for the heat exchangers,
temperature differences for each side of the heat exchanger DTmin HU up Objective Function
are calculated and activated by binary variables if the match 20 50,000 6,439,285
exists. When no match exists between a pair of streams at
a given stage, there is an upper boundary for active tem- 45,000 6,418,713
perature differences. For the hot and cold utilities, similar 40,000 6,435,752
equations exist on the variable temperature side.
35,000 6,491,251

dt( i, j, k, p) ≤ ti( i, k, p) − tj ( j , k, p) 30,000 6,435,752

+ DTup ⋅ (1 − z( i, j , k)), i ∈HP, j ∈CP, k ∈ST, p ∈PR (21.17) 25,000 7,625,869

dt( i, j , k + 1, p) ≤ ti( i, k + 1, p) − tj ( j, k + 1, p) 20,000 7,295,796

+ DTup ⋅ (1 − z( i, j , k)), i ∈HP, j ∈CP, k ∈ST, p ∈PR (21.18) 17,000 INFES

10,000 INFES
dtcu( i, p) ≤ ti( i, NOK + 1, p) − Tcu, out
25 50,000 6,416,403
+ DTup ⋅ (1 − zcu( i)), i ∈HP, p ∈PR (21.19)
45,000 7,591,377
dthu( j , p) ≤ Thu, out − tj ( j ,1, p)
40,000 6,431,203
+ DTup ⋅ (1 − zhu( i)), j ∈CP, p ∈PR (21.20)
35,000 6,410,355
The temperature difference on each side of each heat 30,000 6,431,203
exchanger is then limited by
25,000 6,641,023

dt( i, j , p) ≥ DT min (21.21) 20,000 INFES

18,000 INFES
Next, the total hot utility available can be limited by the
following constraint: 10,000 INFES

30 50,000 6,436,234
∑ qhu( j, p) ≤ HUup,
j∈CP
j ∈CP, p ∈PR (21.22)
45,000 6,435,856
The objective function in [7] contains the following ele- 40,000 6,436,234
ments:
• Unit costs for all heat exchangers including utility 35,000 6,320,508
exchangers, 30,000 6,437,870
• Mean area costs for all matches (i,j,k),
25,000 6,644,294
• Mean area costs for cold utility matches,
• Mean area costs for hot utility matches, 20,000 INFES
• Weighed cold utility costs, and
18,000 INFES
• Weighed hot utility costs.
Finally, the objective function is defined as 10,000 INFES

min TAC =
  To solve the MINLP problem, the model is imple-
AF ⋅  ∑ ∑ ∑ Cf ⋅ z( i, j , k) + ∑ ∑ Cf ⋅ zcu( i) + ∑ ∑ Cf ⋅ zhu( j ) mented in the general algebraic modeling system (GAMS),
 i∈HP j∈CP k∈ST i∈HP CU j∈CP HU 
in which CONOPT is used as the default NLP solver and
B
1  q( i, j , k, p)  CPLEX for the relaxed MIP problem. The solution to the
+ AF ⋅ ∑ ⋅ ∑ ∑ ∑ C⋅  problem was obtained in 45 s using an AMD Athlon™
p∈PR NOP i∈HP j∈CP k∈ST  LMTD( i, j , k, p) ⋅ U ( i, j ) 
B
1.66-GHz processor. Table 21.5 shows the results of the
1  qcu( i, p)  combined MINLP-NLP model for minimal temperature
+ AF ⋅ ∑ ⋅ ∑ C⋅  differences ranging from 20 up to 30ºC. In Table 21.5, the
p∈PR NOP i∈HP  LMTDcu( i, p) ⋅ U ( i, cu) 
B term “INFES” is used when it is impossible to achieve a fea-
1  qhu( j , p)  sible network featuring those upper limits to the hot utility
+ AF ⋅ ∑ ⋅ ∑ C⋅ 
p∈PR NOP j∈CP  LMTDhu( j , p) ⋅ U ( hu, j )  for the given DTmin. These observations are confirmed by
using the pinch analysis to show that the minimal hot util-
DOP ( p)
+∑ ⋅ ∑ Ccu ⋅ qcu( i, p) ity target is violated.
p∈PR NOP i∈HP DTmin has been chosen to vary from 20 up to 30ºC for
the following reasons:
DOP ( p)
+∑ ⋅ ∑ Chu ⋅ qhu( j , p) (21.23) • Some heat exchangers are able to handle minimal tem-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

p∈PR NOP j∈CP perature differences that approximate zero.

AST-MNL58-11-0801-021.indd 535 3/12/13 3:14 PM

536 Petroleum Refining and Natural Gas Processing

Stage 1 Stage 2
1,423 m2
H1
2,863 m2
H2
998 m2
H3

C1
868 m2 2,916 m2 2,240 m2 4,146 m2
C2
1,000 m2 3,394 m2
C3
2,104 m2
C4
150 m2 1,441 m2

Figure 21.3—Final optimal HEN structure.

• The choice of minimal temperature difference depends that can be either integer moves (match exists or not) or
mainly on the fluid used, on the application, and on the continuous moves (increase or decrease flow, heat transfer,
heat exchanger type. and area). The detailed analogy on which SA is based may
• For general hydrocarbon oil heat exchangers, tempera- be found in Kirkpatrick et al. [8]. For any random move,
ture differences below 10ºC on either side of the heat the difference in cost function is then calculated, and the
exchanger cause early fouling of the exchanger. probability of accepting this move is defined by
• Many hydrocarbon oil exchangers prefer a temperature
difference of 20ºC or higher.  − ∆C 
P = exp   (21.24)
• The lowest minimum has been obtained in this range  TSA 
of temperatures.
The maximum value of 30ºC has been chosen because, Many random changes in the design are attempted as the
at higher bounds on temperature difference, there is an annealing temperature is gradually reduced. While one
increase in annualized cost because of the increase in hot is far away from the global optimum and the annealing
and cold utilities used. temperature is high, the probability of an accepted move is
The optimal network for the new model is obtained at very high. The closer one gets to the global optimum, the
a temperature difference bound of 30ºC and a hot utility lower the annealing temperature becomes and the smaller
bound of 35 MW and has a total annual cost of approxi- the probability of accepting a new move. The global opti-
mately €6.32 million. The optimal design of the HEN is mum is reached when the annealing temperature equals
shown in Figure 21.3. absolute zero and no more moves are allowed. In practice,
zero annealing temperature can only be obtained after an
21.3.3 Stochastic Optimization infinite amount of time, for which the global optimum is
Deterministic approaches to solve HEN design problems guaranteed to be found. As can be noticed, “It is the ability
always have their limitations. Sequential approaches to accept ‘uphill’ moves in cost that guarantees that SA will
decompose the problem into smaller-scale problems at generate the globally optimum system if the annealing tem-
the cost of losing accuracy and optimality. Simultaneous perature is reduced to an infinitesimal rate.” [9]
approaches take into account the tradeoff among area, Some papers successfully combined SA with determin-
units, and utility cost but need simplifying assumptions istic optimization methods such as NLP. Athier et al. [10]
to reduce the model to a manageable size. From this proposed an approach in which the HEN configuration is
limitation, the need for stochastic optimization approaches chosen by SA and an NLP formulation is used to optimize
emerges. Stochastic optimization methods do not rely on the operating conditions (temperatures and split rates) for a
any form of superstructure and are often not subject to fixed HEN structure. The four moves in their SA algorithm
any decomposition or simplification. Some of the most fre- are as follows:
quently used methods are simulated annealing (SA), genetic 1. Add a heat exchanger at a randomly chosen point in
algorithm (GA), and the Tabu search method. the network.
2. Delete a randomly chosen heat exchanger and remove
21.3.3.1 Simulated Annealing a split if necessary.
Simulated annealing (SA) is a combinatorial optimiza- 3. Add a splitter on any randomly chosen point in the net-
tion technique that is based on the Monte Carlo principle. work and add one or two heat exchangers depending
The name originates from the analogy with the process of on the topology of the current configuration.
physical annealing, which is the cooling of atoms into a 4. Modify a utility level at a randomly chosen hot or cold
low-energy solid state. This analogy introduces a fictitious utility.
temperature, the ”annealing temperature,” into the opti- The algorithm also features a restore unit that makes
mization process. SA relies on a series of random ”moves”
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
it possible to save and restore the previous configuration
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Chapter 21 n Refinery Planning and Scheduling 537

before the next iteration when a move is rejected. SA has Specify Initial HEN
the advantage that it can reach the vicinity of the global
optimum for nonconvex, nonlinear, or discrete functions
Set annealing temperature
given sufficient solving time. When the problem size is
increased to, for example, a multiperiod HEN design, it has
Repeat
not been investigated yet what effect this will have on the
N times
CPU solving time.
Simulated annealing
21.3.3.2 Genetic Algorithms move
Genetic algorithms (GA) are a relatively new method of sto-
chastic optimization that draws the analogy between com- Multiperiod HEN simulation
binatorial optimization and natural evolution processes. (See Figure 21.5 for details)
The first papers on GA were published in the late 1970s.
In the process of optimization, a set of chromosomes, Objective function evaluation
which represent possible candidate solutions, evolves
toward better solutions. This evolution starts from a ran-
dom population and evolves through different generations. Acceptance
Yes Criterion
In each generation, the fitness of the whole population is No
evaluated and chromosomes are stochastically selected
Accept move Reject move
from this population to form the next generation of popu-
lation, introducing the next iteration in the algorithm.
According to Ravagnani et al. [11], the most important
genetic parameters are the size of the population (affecting
the global performance and efficiency of the algorithm) Reduce annealing temperature
and the mutation rate (avoiding random search and avoid-
ing stationary points).
No Termination
Criterion
21.3.3.3 Tabu Search
Originally proposed as an optimization tool in 1977, this Yes
stochastic method received little attention until the 1990s. Optimal HEN
In general, Tabu search is an iterative improvement
procedure, starting from an initial feasible point while Figure 21.4—SA algorithm for multiperiod HEN design.
trying the better solutions. The search for improvement
in the objective function is based on the greatest-descent is a major drawback when compared with other existing
algorithm. Similar to other stochastic optimization approaches.
approaches, Tabu search has the ability to escape local
optima by using a short-term memory of previous solu- 21.3.3.5 Case Study
tions. Also, Tabu search allows for backtracking to previ- Here the same problem described in Section 21.3.2.1 is
ous solutions, which might lead to a better optimum in solved with SA, to design the HEN in a VGO hydrotreating
subsequent steps. process [14]. The same objective function for a multiperiod
In 2004, Lin and Miller [12] introduced Tabu search as HEN is used to minimize the TAC (i.e., the sum of capital
a method to design and optimize HENs. In their work, Tabu costs [heat exchanger unit costs and maximal area costs]
lists consist of the set of binary variables that represent the and operating costs [hot and cold utility costs] for all of the
heat exchanger match. According to the authors, if the best periods of operation under consideration). The algorithm
neighbor is not better than the current solution, it will be for SA is shown in Figure 21.4.
classified as “Tabu” (forbidden) and added to a recency- The modifications made by the SA algorithm to a cur-
based Tabu list. Old entries are released from the Tabu list rent trial solution are known as random moves. The ran-
at the bottom and new entries are added at the top of the dom moves made by the algorithm depend on the nature of
list. This list forms the short-term memory of the program. the optimization problem and the variables involved. Table
The frequency-based Tabu list keeps track of the frequency 21.6 presents a list of possible SA moves for modifications
at which a certain solution has been visited and provides to a HEN.
the long-term memory of the program. The frequency index
allows Tabu search to determine whether the solution is
trapped in a certain optimum. Table 21.6—SA Moves for HEN Design
Continuous Moves Structural Moves
21.3.3.4 Other Stochastic Methods
A few other stochastic approaches have been studied, such Heat duty change Repipe a heat exchanger
as the randomization approach by Chakraborty and Ghosh Splitter flow fractions change Resequence a heat exchanger
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

[13], in which the network design problem is reduced to Add a new heat exchanger
randomly chosen feasible points. The designer needs to Remove a heat exchanger
predefine the maximal number of exchangers per stream, Add a splitter-mixer unit
Remove a splitter-mixer unit
and, in this model, no stream splits are allowed, which
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538 Petroleum Refining and Natural Gas Processing

environmental regulations; and heavier, sourer, and costly

Table 21.7—SA Parameters Used for crude oils, accompanied by possible disruptions caused by
Optimization of HENs in This Work various factors that companies cannot control. Therefore,
Initial annealing “temperature” 0.10E+10 to maintain the profit margins in this ever-changing market
environment, refiners need to have smarter strategies for
Final annealing “temperature” 0.10E-07
flexible and adoptive operations.
Cooling parameter 0.50E-02 Refinery optimization is to push toward the maximal
profit under certain limitations. The potential benefits
Markov chain length 50
of optimization for process operations in oil refiner-
Acceptance criterion Metropolis ies have long been observed, and refiners are increas-
ingly concerned with maintaining their profit margins
in changing situations by improving their optimization
The SA parameters used to obtain HEN for multipe- strategy. The most successful refineries are those that
riod operation with minimal TAC are presented in Table closely monitor their performances, adjust their opera-
21.7. The TAC for the multiperiod HEN obtained using the tions correspondingly, identify their key weaknesses, and
proposed methodology for the same minimal approach correct them promptly. Although these principles are easy
temperature is 6.34 million (MM) €/year and corresponds to to understand, achieving them is very difficult because of
a reduction of 1 % (65,000 €/year) to the minimum value of the complex nature of the refining business. There are so
the objective function obtained using multiperiod MINLP many decisions involved to achieve the optimal operation
model. The HEN configuration for multiperiod operation for a refinery. All decisions are highly interrelated and the
obtained by SA is presented in Figure 21.5, which shows interactions have a large effect on overall refinery profit.
the maximal heat duty of each match from all of the three Optimization of an individual department or decision
operating periods under consideration. does not guarantee the optimal performance of the overall
In this case study, SA gives better results than the deter- refinery.
ministic method (CONOPT + CPLEX) for the MINLP prob-
lem. However, this is not to say that SA is better for solving 21.5 Emerging Techniques
general optimization problems. Because of random search Facing various challenges in the ever-changing refining
algorithms, stochastic methods such as SA, GA, and Tabu landscape, it is essential that refiners raise their operations
search tend to be more time-consuming in computation, to new levels of performance. To gain the greatest potential
less consistent in solution quality (different solutions for benefit, some of the key areas related to refinery optimiza-
different runs), and less efficient in dealing with continu- tion are identified:
ous variables. There is a growing trend nowadays to adopt • Moving toward molecular management,
hybrid optimization approaches that combine determinis- • Improved solution strategies for planning and scheduling,
tic methods (methods for LP and NLP such as Simplex and • Multisupply chain management, and
SQP) and stochastic methods. • Refinery reliability and maintenance management.
Because crude oils and high-boiling crude oil fractions
21.4 The Challenges of Refinery are composed of many members of a homologous series of
Optimization relatively few hydrocarbons, the composition of the total
The refining industry deals with one of the world’s longest mixture, in terms of elementary composition, does not vary
and most complex supply chains, beginning at a natu- a great deal. However, small differences in composition can
ral resource in the ground and continuing all of the way greatly affect the physical properties and the processing
through to the end-users. The current picture of the refin- required for producing saleable products. In the meantime,
ing industry is characterized by stiff competition; stricter refinery products are increasingly specified according to

Cold Utility
14.7 MW
H1
15.4 MW
H2
9.8 MW
H3

C1
15.3 MW 13.0 MW 27.8 MW 3.2 MW
C2

14.2 MW 6.7 MW
C3
10.9 MW 6.3 MW 9.1 MW
C4

Hot Utility 9.1 MW

Figure 21.5—HEN for multiperiod operation by SA.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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Chapter 21 n Refinery Planning and Scheduling 539

their molecular composition. Therefore, it is inevitable to Although not the only constraint, scheduling inventory
include molecular information in petroleum mixture char- is a prerequisite to more elaborate or optimal schedules.
acterization [15]. The representation of petroleum mixture Scheduling has the challenging task to translate planning
composition in a modeling and optimization framework economic objectives into time-stamped operating instruc-
is currently limited by a lack of availability of laboratory tions such as lining up a tank to a jetty or setting a com-
data (composition, thermodynamics, and kinetic proper- ponent flow to a gas oil blender. Somehow, scheduling is
ties estimation) and available numerical methods to solve the bridge between traders and operators. In that respect a
large size problems with detailed representation. However, refinery scheduler is probably the staff member having the
a promising development has been made to overcome this widest knowledge of practical operations.
major obstacle [16]. Proper scheduling of operations is becoming more
In addition to molecular characterization of refinery important because the economic environment is increas-
streams, today’s ever-increasing computing power com- ingly demanding.
bined with advances in optimization techniques makes it • New commercial specifications, most particularly the
possible to robustly solve large and complex refinery opti- low sulfur content of automotive fuels, have an effect
mization problems that were previously not feasible, such on the proper scheduling of tank allocations, line-up
as integration of cargo scheduling, feedstock managing and selection, and blend sequences to minimize the risks of
monitoring, refinery scheduling, and pipeline scheduling contamination.
throughout the whole oil supply chain. Deterministic and • New crudes or condensates are processed with increas-
heuristic solvers have been developed to allow us to extend ing requirements of segregation by yields, suitability
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

traditional LP optimization to include nonlinear and mixed for bitumen production, and sulfur and metal content.
integer optimization and therefore accurately reflect the • Shareholders generally limit the available storage for
actual operational capability and the constraints of a par- crudes, intermediate streams, and products to mini-
ticular refinery. However, much research is required before mize the financial costs of excessive inventory.
the daily or hourly decision-making process in refineries • Market trends are becoming more dynamic, request-
can be practically optimized. ing frequent swings of operating conditions and tank
It is also important to recognize that more supply allocations. This is in particular critical for processing
chains intersect the refinery in addition to oil. Among them refineries.
are petrochemical, gas, hydrogen, and power supply chains. • Laaschuit [17] and Pinto et al. [18] provide good intro-
There is no doubt that it has great economic potential to ductions to scheduling as part of a global supply chain
simultaneously address the planning of these multiple sup- and to planning and scheduling in oil refineries.
ply chains, with major challenges in quality/composition
management as well as process integration for tailor-made
feedstocks and intermediates to suit consumers in different 21.7 Definition of Oil Refinery Scheduling
supply chains. Some companies and researchers are begin- The oil refineries short-term scheduling problem can be
ning to address this problem. formulated as follows:
Unscheduled shutdowns are always moaned by refin- • Given
eries. However, most refineries do not plan for them • LP plan averaged targets over the reference time
because it is a common belief that it is something not horizon (typically a month);
predictable. Although the unscheduled shutdowns may • Present status of inventory and process conditions;
not be entirely avoidable, they are certainly reducible by • Present and planned equipment availability and
using real-time operating information to predict the health schedule of turnarounds; and
of the equipment and process and performing necessary • Future receipts/liftings qualities, volumes, and dates.
preventive maintenance actions. Progress has been made • Find the sequence of optimal dates for
in various technologies such as equipment monitoring, • Crudes and condensates atmospheric distillation
dynamic performance management, prediction of process unit (ADU) feed mix and swings;
degeneration, and preventive maintenance scheduling. • Crude, rundown, and finished product tank alloca-
The major challenge in this area is how to integrate the tion changes;
individual techniques to form a systematic procedure. • Process unit operating mode changes;
Some promising progress has been made in the example of • Oil movement operations, such as transfers from
liquefied natural gas plants, but not to the overall refinery tanks;
to date. • Batch operations, such as blends and transfers via
shared process lines; and
• Commercial product blending recipe changes.
21.6 Refinery Planning and Scheduling • Under the following constraints:
It is essential to recognize that scheduling is about • Thermal constraints, such as furnace duties and
finding feasible operating instructions under short- skin temperatures;
term constraints. In that respect, the initial goal • Hydraulic constraints;
of the scheduler is to operate the plant within the • Hydrogen balance;
c onstraints of a mostly fixed feedstock receipt and • Environmental constraints and sulfur balance;
product d elivery schedule (with some flexibility) to • Fuel gas and steam balance; and
satisfy the optimal plan objectives (operations and • Storage segregation requirements.
ending i nventories) while not overflowing any tank or • Subject to unexpected events, such as
sucking any tank dry. • Changes from marketing (crudes and products);
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540 Petroleum Refining and Natural Gas Processing

•
Modification of planning objectives due to a new • Tactical planning for annual operating budgets and
economic environment; implementation of new refining schemes; and
• Unplanned shutdowns of process units; • Operations planning, typically the monthly plan, the
• Unavailability of major equipment; link with scheduling.
• Process units upsets; The limitations of LP are well known and have been
• Estimated time of arrival (ETA) changes; and in particular listed by Neiro and Pinto [20] and by Hart-
• Weather conditions affecting operations, liftings, mann [3]:
and receipts. • All processing options are preselected. In some situa-
Unit prices and costs are generally not used by sched- tions, the scheduler shall have to use additional degrees
uling systems as the economical optimization is performed of freedom and find alternate paths to provide a fea-
by the planning tools. In case of significant changes to the sible execution plan.
economic environment, the LP model can be adjusted to • Not all constraints can be modeled, for instance,
produce new targets for the scheduling. In some cases, because they are highly nonlinear or heavily depend on
notably blending, there can be opportunities for local eco- real-time process conditions. Constraints are generally
nomic optimization by the scheduling system but always limited to mass balances and inventory limitations.
constrained by the LP target. • The consideration of time is limited to the starting
and end dates of the LP model period. LP does not
answer the essential requirement of scheduling: when
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

21.8 Business Incentives to perform actions. In particular, such control variables

Benefits from optimal scheduling are always site specific as blend recipes or conversion unit severities are only
and therefore need to be computed on a case-by-case basis. averages over the plan time horizons.
They generally fall into the following main categories: • All streams are assumed to be segregated. However, see
• Higher throughput reference 3 for the use of recursion techniques (succes-
• Crude distillation (swings, mix, and tanks) sive linear programming).
• Blenders (tanks, marketing) • Nonlinear properties in the gasoline and middle distil-
• Improved balances late pools are simulated with blend indices that may
• Hydrogen (process units operations) have limited accuracy. However, there has been signifi-
• Sulfur (environmental constraints) cant progress in the recent years.
• Lower operating costs • NLP technology can include a blending library to
• Tank inventory rigorously model complex blending correlations.
• Demurrage • Blend indices can be updated from near-infrared
• Enforcement of planning objectives (NIR) spectra.
• Increased flexibility • Changes in a few input data can induce significant
• Reaction to unexpected events modifications to the optimal solution.
• Capture of marketing opportunities. • Complex LP models are difficult to maintain so that
In addition to quantitative benefits, an integrated they keep reflecting the reality of the refinery (crude
scheduling system also brings qualitative rewards, includ- slate, import feeds or blend components, yields, topol-
ing better teamwork across marketing, technical services, ogy, limitations, and other databook elements).
and operation departments. • Users of LP solutions are engineers of the planning/
scheduling department of the refinery, not the control
room operators.
21.9 Planning Versus Scheduling • Economics are of interest, with an optimal gross mar-
Planning and scheduling systems, although tightly inte- gin as objective function and marginal costs of con-
grated, have different goals and require different techniques strained variables.
[19]. In scheduling tools that provide feasible operation • Outputs of LP models are inventory levels at the end
short-term plans, the target provided by the LP model is of the period and mean targets for selected operat-
taken as the economic objective with penalties in case of ing parameters such as blend recipes or process units
deviations. severities.
The main question for schedulers is “when?” regarding A monthly refinery LP model definitely remains the
events and constraints that are generally not represented in best possible tool to have an economical target, the optimal
the planning model. Scheduling requires tools other than economic function, considering supply, demand, prices,
LP to cope with unexpected upsets, short-term fluctuations and some constraints. For the above reasons, it is not the
of demand and supply, transient situations, and limitations tool to produce feasible short-term operational schedules.
of inventory. Progress has been made in recent years to automatically
One of the major challenges in mathematical program- update parts of the LP model, in particular using blend
ming for oil refineries is the proper integration between the indices computed from NIR spectra [21].
planning LP models and the scheduling tool. LP models are
excellent tools for planning activities, such as equilibrium 21.10 Scheduling and Complexity
between supply and demand over a month. Planning mod- 21.10.1 Scheduling Time Horizon
els can be classified into The scheduling time horizon is generally defined by the
• Long-term strategic planning for such exercise as the availability of reasonably firm receipts and lifting dates.
5-year capital investment plan, frequently making use In some easy cases, the supply chain is very regular with
of integer programming; significant advance notice of changes to the lifting plan.
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Chapter 21 n Refinery Planning and Scheduling 541

Coastal refineries can face significant time variations

because of weather conditions. For example, North Sea Table 21.8—Western European Refinery
crude receipts can be delayed by several days. As a conse- Scheduling Complexity
quence, scheduling time horizon can vary between a week Crude slate 20–40 different crudes per year
and a month. It is important to choose a representative
Tank farm 100–400 tanks
period and whenever possible to be in line with the plan-
ning period. As an example, a 10-day scheduling time Product grades 20–50 Mogas, middle distillates
integrated with a 3 × 10 day rolling multiperiod LP plan is
Imports 10–20 feeds, blend components
generally convenient.
Process units 10–50
21.10.2 Data Granularity and Precision Mogas blend components 6-18
Short-term scheduling is interested in precise prediction of
future operations; for instance, filling an expedition tank Middle distillates components 4–12
with the right quality determinations at the right time to Ships and barges 50–250 ships per month
meet a contractual lifting. This requires precise timing and
high-fidelity quality predictions. Consequently, the real- Trucks 300–900 trucks per day
time database must collect simultaneous variables with a Crude swings 3–10 per week
time granularity compatible with the most dynamic operat-
Oil movement operations 10–100 per day
ing conditions, generally a few minutes. To avoid any bias,
all critical process variables should also be reconciled by
proper real-time algorithms.
even interest to explore all routing alternatives as part of
a scheduling tool, and this task should be left to the dis-
21.10.3 Offsite Scheduling tributed control system-based oil movement systems that
Refinery offsites are a challenge for a scheduling system have powerful algorithms to search complex graphs and
because they offer many degrees of freedom [22]. As illus- rank alternative line-ups with such criteria as minimizing
trated by Figure 21.6, a medium-size refinery can offer flushing or pumping costs. However, many of the schedul-
many possible routes. ing decisions should relate to offsites, which is one of the
It is very important to select which offsites decision reasons why scheduling is so complex, as illustrated by the
variables shall be manipulated by the scheduling system typical dimensions for a refinery offsite system (Table 21.8).
such as assignment of one out of N unloading jetties to one With limited storage dictated by financial consider-
out of M crude tanks. There is no practical possibility or ations, offsite scheduling is becoming increasingly critical.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Figure 21.6—Offsite scheduling.

AST-MNL58-11-0801-021.indd 541 3/12/13 3:14 PM

542 Petroleum Refining and Natural Gas Processing

OFFSITES
Level 4 BLENDERS, TANK FARM, RECEIPT AND SHIPPING FACILITIES
Corporate / Plant
Business CORPORATE PLANNING (LINEAR PROGRAMMING)
FINANCE
SUPPLY
Information MARKETING ACCOUNTING
Systems

REFINERY / PLANT MONTHLY PLANNING (LINEAR PROGRAMMING)

MAINTENANCE
Level 3 INSPECTION
Plant PERFORMANCE
SHORT TERM OPERATIONS SCHEDULING & OPTIMIZATION
Management
MONITORING
Information EMISSION
Systems ASSETS
PLANT-WIDE MASS BALANCE MONITORING
MANAGEMENT

Level 2 ON-LINE
PROCESS UNIT
Process ON-LINE DATA OPTIMIZATION BLEND QUALITY
RECONCILIATION LIMS
Validation & CONTRL &
OPTIMIZATION
Optimization
MOVEMENT
ADVANCED TANK FARM MANAGEMENT
Level 1 MANAGEMENT MONITORING &
PROCESS
Process AUTOMATION
Automation AUTOMATION BLEND RATIO
NEAR INFRARED
CONTROL
& Control

SENSORS, ACTUATORS, ANALYZERS SENSORS, ACTUATORS

Plant
Facilities PROCESS AND UTILITY UNITS OFFSITES BLENDERS, TANK FARM, RECEIPT AND SHIPPING

Figure 21.7— Information flows in refinery decision support systems.

21.10.4 Scheduling and System Integration • Laboratory information management system (LIMS),
21.10.4.1 General • Computerized maintenance management system
As illustrated by Figure 21.7, scheduling is a node for infor- (CMMS),
mation flows. • Planning system,
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

• Performance monitoring system, and

21.10.4.2 System Architecture • Offsites management system (tank management and
To avoid large combinatorial problems that are difficult line-up management).
to solve in a reasonable time, three main subsystems that Information requirements typically include
address different areas of the processing can be solved • Structural data
concurrently: • Refinery topology
1. Crude optimization, • Process unit capacities
2. Process unit scheduling, and • Tank capacities and possible allocations
3. Gasoline blend scheduling. • Description of loading/unloading facilities
These subsystems are integrated so that decisions and • Crude data
results are automatically passed from one subsystem to the • Crude assays (sufficiently detailed)
others. The scheduling application is also integrated within • Real-time data
the refinery system environment to facilitate the access to • Tank inventory
input/output data. • Process stream flows and quality determinations
To be practical, a scheduling system must apply the fol- • Marketing data
lowing main concepts: • Crude availability: quality, volume, and ETA
• The scheduling application is a rolling application and • Forecasted liftings: grades, volumes, and ETA
the time horizon can be different for each subsystem. • Planning data
• All decisions generated by the application can be over- • Monthly LP plan: average targets
written by the user.
• The application must allow teamwork.
• The application must be robust and must provide 21.11 Mathematical Tools for
results easy to understand and to check. Scheduling
• The application must provide facilities to store case 21.11.1 General
studies as reference files. With high process scheme complexity, large crude slate,
and very dynamic markets, scheduling departments need
21.10.4.3 Integration with Management more than a spreadsheet to find an optimum among a myr-
Information Systems iad of feasible alternatives. Optimal scheduling is a chal-
A successful implementation of scheduling in complex lenging problem from the mathematical viewpoint because
refineries is highly dependent on a robust and efficient it combines discrete and continuous time representation
management information system (MIS) that automates with hundreds of discrete decision variables. Scheduling
secure flow of information between scheduling and the fol- deserves its reputation of complexity and remains the sub-
lowing subsystems: ject of university research [23–27].
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Chapter 21 n Refinery Planning and Scheduling 543

21.11.2 Requirements for Scheduling Tools 21.11.3.4 Discrete Optimization Method

Scheduling systems are used to provide an answer to the A review of optimization techniques is given in references
following questions: When and how do we modify operat- [33] and [34]. Enormous progress has been made in the last
ing conditions, and what do we do in case of an unexpected 25 years, and mathematical programming techniques are
event? Users are the engineers of the planning/scheduling now being used in real time to optimize nonlinear processes.
department of the refinery and control room operators. Microsoft Excel includes a gradient-based NLP solver.
Outputs are warnings on constraints violations and instruc- Optimization techniques used for scheduling include
tions to the control room operators that can be translated essentially MILP and MINLP, today certainly the most
into set points or instructions to field operators. Economics appropriate technologies to solve large supply chain optimi-
are considered as given by the LP model through the mean zation problems, in some cases with over 100,000 variables.
optimal operating conditions. Unlike LP models, schedul- An introduction to MINLP is given in references [35–37].
ing systems are connected to the real world in real time and Subject to constraints on the number of binary vari-
take into account unexpected events. Special care must be ables and the stability of the solution, MILP is well suited
given to the integrity of automated data collection. to solve combinatorial problems. However, MILP problems
are NP-complete; that is, the computation time increases
21.11.3 Mathematical Programming exponentially with the number of decision variables. This
Technologies remains a limitation when solving large scheduling prob-
Scheduling systems typically combine several software lems [38]. More recently [39], scheduling optimization
technologies to solve the scheduling problem [28,29]. under uncertainty is becoming feasible using concepts from
fuzzy set theory and interval arithmetic.
21.11.3.1 Simulation
Whenever there is a need for accuracy, using LP yield and 21.11.3.5 Other NLP Techniques
quality vectors to represent the output of a process unit is One example is the use of zonotopes to maximize the flex-
not sufficient. Consequently, scheduling systems can in some ibility of producing future blends. The technology is used to
instances have a library of simplified process unit models solve the problem of the paint dealer that has units of gray,
that use shortcut methods or correlations that can be tuned white, and black paints and must satisfy successive client
to the actual plant operations. For example, this possibility demands by mixing its stock. The problem is how to man-
has proved to be useful for such major units as the ADU or age this stock and maximize the probability of answering
for fluid catalytic cracking ( FCC), for instance, to have an future client orders.
accurate prediction of middle distillate pool qualities. This geometric management of the stock has been
applied by TOTALFINAELF [40] on middle distillates.
21.11.3.2 Rules When the demand statistical distribution can be estimated,
Rules can be used, sometimes as part of an expert system, the method can incorporate this partial knowledge of the
whenever operational practices can be modeled. These future to provide an optimal sequence of blends. Other
rules include those of tank allocation for process units potential techniques for optimization include
feeds or rundowns and rules for settling or draining tanks. • Direct search methods and derivative-free optimization
In some cases, expert systems and mixed integer program- (DFO),
ming can be used as a hybrid system [30]. • SA,
• Ant colony algorithm,
21.11.3.3 Constraint Programming • GA,
Constraint programming is a logic-based optimization tool • Greedy algorithms (often used to find initial solutions),
to take care of multiple constraints and reduce the com- • Tabu search,
binatorial aspect of the scheduling problem. Constraint • Variable neighborhood search, and
logic programming (CLP) is well suited to solving large • Smoothing methods.
combinatorial problems [31], known as NP-complete, that
can be found in resource allocation (e.g., ships to births). 21.12 Industrial Applications of
Such large problems can easily exceed present and near- Scheduling
future computing capabilities if they are tackled by system- The most famous industrial scheduling applications include
atic search procedures that explore all tree branches and • The travelling salesman problem,
backtrack when reaching dead ends. CLP includes specific • Time table optimization, and
knowledge about variables and makes use of constraints to • Fleet routing.
limit the search domain. In the oil refining industry, the most common schedul-
Constraint handling languages allow for controlling ing applications relate to crude oil, blending, and logistics.
the search strategy and the definition of such global con-
straints as 21.12.1 Crude Oil Scheduling
• Cumulative constraints to express cumulative resource Regarding advanced process control (APC), the crude dis-
limits over a period; tillation units are primary targets for optimal scheduling
• Disjunctive constraints to express nonoverlapping [27,41–46]. In many process schemes, it is essential to oper-
tasks, a frequent problem in discrete manufactur- ate the crude unit at its maximal capacity and with proper
ing; and cut points to obtain the best possible feeds for downstream
• Precedence constraints. units.
An example is given in reference [32] for the lubricant The problem is not always trivial because it is unusual
manufacturing industry. for a refinery to process only a couple of crude oils with
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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AST-MNL58-11-0801-021.indd 543 3/12/13 3:14 PM

544 Petroleum Refining and Natural Gas Processing

for discrete manufacturing such as automobile or batch

Table 21.9—Crude Scheduling Problem Size chemistry than for oil refining.
Crude slate 20–40 different crudes per year Several companies offer suitable scheduling software
technologies with various degrees of complexity, from
Crude tankers capacity 200–1,000 kbbl
simple spreadsheet simulation to partial optimal schedul-
Crude jetties 2–4 ing. In particular, the selection criteria should include [53]
• Adequacy of the scheduling tool to the specific refinery
Remote crude tank farm 5–12 tanks
problem(s),
Refinery crude feed tanks 2–5 tanks • Maintainability of models by the refinery staff,
ADU units 1–4 • Long-term support from the software vendor,
• Ease of integration to the refinery MIS and enterprise
Vacuum distillation units (VDU) 1–4 resources planning (ERP) to avoid manual entries, and
Crude swings 3–10 per week • Use of modern IT technology [39] to avoid short-term
obsolescence:
• Service-oriented architecture,
plenty of storage. In Western Europe and processing refin- • Web services, and
eries worldwide, the crude slate is very significant and • Object-oriented data model.
logistics are heavily constrained.
Whenever the crude oils are received by pipelines,
the refinery tools must be synchronized with the pipeline 21.14 The Human Factor
scheduling system to anticipate the batch deliveries and The planning/scheduling department of oil refineries gener-
associated constraints of volumes and qualities, such as ally has a high profile in the organization [54]. Quite often
buffer zone tank allocation. The size of the problem can regrouped with economic studies and performance moni-
justify advanced optimization methods (Table 21.9). toring staff, the schedulers of complex European refineries
The most difficult issues include play a major role in day-to-day operations.
• The approximate knowledge of crude assays, From a head-count viewpoint, the range is 4–10 sched-
• The time periods for settling and dewatering, ulers, mostly depending on the complexity of operations.
• The flushing periods of shared pipelines, The optimal blend of skills is obtained by a team of
• Operational staff having a long experience of the refin-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

• The uncertainty on ETAs for crudes delivered by

tankers, ery, especially oil movement, and
• The crude segregation requirements, including: • Bright engineers with open minds to find new solutions
• Sulfur content, and test new tools.
• n-Paraffins content for arctic middle distillates, Even more than for any other computerized systems,
• Suitability for production of bitumen or base oils, the quality of the staff is the prime success factor, along
• Hygroscopic crudes, and with their ability to work as a single team. The staff com-
• Metal content for a delayed coker unit. prises crude traders, marketers, logistics specialists, pro-
cess engineers, laboratory chemists, and field and control
room operators.
21.12.2 Blending Scheduling
Short-term scheduling of transportation fuel blends is also
a major concern because it is closely related to the schedule
21.15 Conclusions
There is a huge potential for hard benefits capture when
of commercial product liftings. Here again, the objective
using optimal scheduling in process plants with high
is to have a minimal inventory but still meet all demands
supply/demand dynamics, severe constraints, and large
[45,47–51].
operational flexibility. The issue is complexity: Solving the
The use of advanced inline analytical technologies
optimal scheduling problem of an oil refinery from incom-
affects the product delivery business processes. In par-
ing crude to commercial product liftings is at the edge of
ticular, inline certification of commercial products can
the present mathematical programming technology.
reduce the level of inventory required to satisfy the market
No process plant can afford to keep a team of PhDs
demands. The difficulty of short-term blending scheduling
in mathematics to run the scheduling system; therefore, a
is dependent on the number of grades, the dynamics of
compromise is required to have a manageable and robust
the commercial contracts, and the number and capacity of
solution to the optimal scheduling problem. Proper rep-
tanks for blend components and commercial products.
resentation of constraints, concurrent use of different
mathematical programming techniques, and integrations
21.12.3 Lube Oil Production of scheduling subsystems are key prerequisites to success.
Lube oil production is a combination of continuous and
batch processes and is therefore very complex from a
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Diesel: Uma Aplicação Industrial, PhD Thesis, University of [54] Freyman, D.G., and Brumbaugh, M.A., “Identifying Roles,
Campinas, Campinas, Brazil, 2008. Responsibilities Optimizes Refinery Scheduling Process,” Oil
[52] Barbariol, S., Lusetti, M., Mantilli, M., and Scarioni, M., Lube Gas J., October, 2005, pp. 70–73.
Production Scheduling Model at the AGIP Petroli Livorno Refin-

Appendix C €/unit Area cost coefficient for heat

Abbreviations exchanger
CLP Constraint logic programming Cp [kJ/kg·K] Specific heat capacity
CMMS Computerized maintenance management system Ccu €/unit Per unit cost for cold utility
DFO Derivative-free optimization Cf €/unit Fixed charge for heat exchanger unit
EOR End of run Chu €/unit Per unit cost for hot utility
GA Genetic algorithm Cw - Weight parameter for decrease of
HEN Heat exchanger network areas

LP Linear programming DOP(p) - Duration of period

MILP Mixed integer linear programming DTup [ºC] Upper bound on temperature
difference
MINLP Mixed integer nonlinear programming
epsi [ºC] Exchanger minimal approach
MIS Management information system temperature
MOR Middle of run Fi(i,p) [kW/K] Heat capacity flow rate of hot stream
i
NLP Nonlinear programming
Fj(j,p) [kW/K] Heat capacity flow rate of cold
SA Simulated annealing
stream j
SOR Start of run
HUup [kW] Upper bound on total hot utility
TAC Total annualized costs available

VGO Vacuum gas oil MAXarea [m2] Upper bound on heat transfer area
(i,j,k) for exchanger connecting streams i
and j in stage k
Indices
NOK - Number of stages
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

i Hot process stream or hot utility

NOP - Number of periods
j Cold process stream or cold utility
Qup [kW] Upper bound on heat exchange
k Stage number or temperature interval capacity
p Period of operation SplitC - Existence of split on cold stream j at
stage k
Sets SplitH - Existence of split on hot stream i at
CP Set of a cold process stream j stage k

HP Set of a hot process stream i Tiin [ºC] Inlet temperature of hot stream

PR Set of an operation period, p = 1,…, NOP Tiout [ºC] Outlet temperature of hot stream

ST Set of a stage in the superstructure, k = 1,…, NOK Tjin [ºC] Inlet temperature of cold stream

Tjout [ºC] Outlet temperature of cold stream

Parameters
U [kW/m2K] Overall heat transfer coefficient
Units
z1(i,j,k) - Existence of match (i,j) in stage k
AF - Annualization factor
zcu1(j) - Existence of cold utility match for hot
B - Exponent for area cost stream i

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Chapter 21 n Refinery Planning and Scheduling 547

zhu1(i) - Existence of hot utility match for cold qcu(i,p) [kW] Heat exchanged between hot stream
stream j i and cold utility in period p

qhu(j,p) [kW] Heat flow exchanged between cold

Variables stream j and hot utility in period p

Units s(i,j,k,p) - Slack variable

A(i,j,k) [m2] Maximal area for match of hot smin(i,j,k) - Minimum of s (i,j,k,p) for match i,j,k
stream i and cold stream j in stage k
tcs(i,j,k,p) [ºC] Temperature of cold stream fraction
Acu(i) [m2] Maximal area for match of hot after exchanger i,j,k in period p
stream i and cold utility
ti(i,k,p) [ºC] Temperature of hot stream i at hot
Ahu(j) [m2] Maximal area for match of cold end of stage k in period p, exchanger
stream j and hot utility inlet

dtcu(j,k,p) [ºC] Temperature difference for match ti(i,k+1,p) [ºC] Temperature of hot stream i at hot
of hot stream i and cold utility in end of stage k in period p, exchanger
period p outlet

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
dthu(i,k,p) [ºC] Temperature difference for match ths(i,j,k,p) [ºC] Temperature of hot stream fraction
of cold stream j and hot utility in after exchanger i,j,k in period p
period p
tj(j,k,p) [ºC] Temperature of cold stream j at hot
dt(i,j,k,p) [ºC] Temperature difference for match end of stage k in period p, exchanger
(i,j) at temperature location k in outlet
period p
tj(j,k+1,p) [ºC] Temperature of cold stream j at hot
fc(i,j,k,p) [kW/K] Heat capacity flow rate of cold end of stage k in period p, exchanger
stream fraction related to exchanger inlet
i,j,k

fh(i,j,k,p) [kW/K] Heat capacity flow rate of hot stream

fraction related to exchanger i,j,k
Binary Variables
obj - Objective function, total annualized
zcu(i) Existence of cold utility match for stream i
cost
zhu(j) Existence of hot utility match for stream j
q(i,j,k,p) [kW] Heat exchanged between hot stream
i and cold stream j in period p z(i,j,k) Existence of match between i and j in stage k

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AST-MNL58-11-0801-021.indd 548 3/12/13 3:14 PM

22
Transportation of Crude Oil, Natural Gas,
and Petroleum Products

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
Luis F. Ayala H.1

22.1 Transportation Overview comes out ahead for transportation over short distances
On a daily basis, petroleum products are transported from and can be used over relatively longer distances as long
source to market inland and across the oceans. The annual as larger volumes justify their installation. This is always
volume of petroleum fluids traded and transported world- the case for regional trade, in which pipelines remain
wide is mind boggling. In 2008 alone, more than 19 billion unsurpassed as the most efficient means of transportation
bbl of crude oil and 28 trillion cubic feet of natural gas were within continental boundaries. As transportation distances
traded across international boundaries [1]. The same year, increase, pipelines can become uneconomical and marine
the world consumed approximately 31 billion bbl of crude transportation must be considered (oil tankers for crude
oil and 104 trillion cf of natural gas [2]. Transportation, as oil; liquefied natural gas, compressed natural gas, and gas-
the economic activity that fixes the geographical imbalance to-liquid options for the case of natural gas). Transportation
between markets and producers, represents the backbone beyond a radius of 2000 km (1243 miles) would typically
of international trade. Transportation also permeates every require marine transport.
aspect of the daily life within the boundaries of countries, An important factor for consideration when examining
states, or municipalities. In fact, reliable and uninterrupted the cost-effectiveness of transportation is its energy effi-
distribution of energy commodities to consumers is now ciency, or the amount of energy able to be moved per unit
taken as an implicit characteristic of any functional modern volume of transportation capacity or per dollar of trans-
society. portation expense. From this point of view, oil and liquid
Different methods of transportation are available products typically have the upper hand over natural gas
depending on the type and quantity of transported fluid and because they are able to pack the most amount of energy:
distance of delivery. Not surprisingly, the main factor driv- 1 cf of crude oil can roughly contain as much energy as
ing the selection of the appropriate transportation mode 1,000 scf of natural gas—this works out to a 1:1,000 energy
is cost. The most cost-effective mode of transportation for ratio. This unfavorable energy ratio makes natural gas sig-
any given application is the one that can reliably move the nificantly more costly to transport compared with oil on a
commodity from source to destination with the minimum unit volume of transportation capacity basis. This also rein-
expense—which is a strong function of distance traveled forces the selection of pipelines—the transportation mode
and transportation volume. with the least capital expense and associated maintenance
Most of the transportation of oil and gas operates in overhead—as the method of choice for transportation of
one of two modes: pipeline transportation for inland and relatively small-to-medium volumes of petroleum products.
transcontinental trade and marine transportation (tankers) The key to economical transportation of large quanti-
for international or intercontinental trade. Ocean tankers ties of natural gas lies in the ability to compress it into
are the most common method of internationally mov- significantly reduced volumes so that its transportation effi-
ing petroleum products. Marine transportation systems, ciency can be maximized. The largest volume reduction for
or tank fleets, are the primary option available for long- natural gas can be obtained through outright liquefaction
distance transportation of internationally traded energy (LNG, or liquefied natural gas), which can realize a 1:600
commodities because they make use of a vast network of reduction in volume. LNG currently dominates the market
vessels and ports at a global scale. However, at some point for maritime transportation of natural gas. Liquefaction is
the marine network relies on inland transportation systems the most drastic reduction of volume that can be accom-
for final distribution of goods to the markets. For the case plished for any given natural gas volume, but it entails a
of inland fluid transportation, one of the most effective and significant capital expense. Such a significant expense can
efficient means of transportation is the use of pipelines. only be offset by the handling of significantly large gas vol-
Pipelines are convenient to manufacture and install and umes over long transoceanic distances—distances for which
are typically characterized by a significantly long life span, any other method would become unreasonably uneconomi-
better assurance of continuous delivery, and lower mainte- cal. For this reason, Wang and Economides argue that, for
nance costs. Whenever distances are not prohibitive, pipe- smaller volumes of gas over shorter distances, compressed
line transportation almost always turns out to be the most natural gas (CNG) can become economically more attrac-
economical means of fluid transportation. This situation is tive than LNG for maritime transport, as shown in Figure
illustrated in Figure 22.1 for the case of transportation of 22.1 [3]. CNG technology can achieve up to a 1:200 reduc-
natural gas. In this figure, pipeline transportation always tion in volume with a significantly less capital investment
1
The Pennsylvania State University, University Park, PA, USA
549
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550 Petroleum Refining and Natural Gas Processing

16 uitous in all refineries and industrial facilities because they

14 provide the connectivity that is needed among all process
equipment. Pipeline transportation provides a versatility
Gas delivery (bcm/year)

12 Pipeline LNG
rarely found in other modes of transportation. Advances
10 LNG + GTL? in pipeline engineering made it possible to place pipelines
8 in many different environments, including deserts, ocean
6 floors, forests, and mountain ranges. Some of the versatility
h
TL) - Fischer Tropsc can come with a strategic cost because pipelines are fixed
4
CNG Gas-to-Liquids (G
E) in place and could be more readily vulnerable to deliberate
2 GTL (Methanol DM
Stranded or Possibly acts of disruption, international disputes over right of ways
0 and associated tariffs, and associated political risk.
0 1,000 2,000 3,000 4,000 5,000
Distance to consuming market (km)
22.2 Pipeline Sizes and Standards
Figure 22.1—Transportation options for natural gas. Source: [4]. In the United States, pipes are manufactured in accor-
dance to various specifications and standards set forth by
American Society for Testing and Materials (ASTM Interna-
when compared with LNG. Other transportation options, tional), American Petroleum Institute (API), ASME (Ameri-
such as gas hydrates and gas-to-liquids (GTL), have also can Society of Mechanical Engineers), and ANSI (American
been suggested. GTL entails a chemical transformation of National Standards Institute). Table 22.1 shows some com-
natural gas molecules into larger hydrocarbon molecules monly specified piping materials used for pressure applica-
that can be sold and transported as premium fuels, signifi- tions that typically require steel alloys. API specifications
cantly increasing the underlying value of the fuel [5]. Alter- 5L and 5LX, common choices in the oil and gas industry
native gas transportation options, such as LNG operations, along with ASTM A53 and A106, provide guidance for the
are discussed elsewhere in this handbook. Another option manufacturing and testing of steel pipes for refinery and
that has received some attention is the transformation of transmission service. Low-pressure water, oil, and gas ser-
natural gas into its hydrated form. It produces volume vice can use nonmetallic piping material whenever their use
reductions of up to 1:180 and thus it has been studied as can be justified, which commonly leads to lower capital and
another potential means of natural gas transportation [6]. maintenance overheads. However, steel pipes are required
In comparison, pipeline applications can accomplish up in any high-pressure application.
to a 1:100 reduction in volume for high-pressure applica- All commercial steel pipes, regardless of their material
tions that use high-grade pipe materials with greater pipe specification (Table 22.1), are manufactured with dimen-
thicknesses. sions (diameter and thickness) that comply with standard-
Among all of these transportation options, pipelining ized designators described by ASME standards B36.10M
remains the most popular and customary method of mov- and B36.19M for welded/seamless wrought and stainless
ing petroleum fluids from source to destination for inland steel, respectively. Pipes used in industry must be dimen-
and near-shore applications. As such, they are the target of sionally manufactured in compliance with these ASME
study in the transportation chapter of this handbook. In the standards as per the requirements of the various ASME
petroleum industry, all producing wells are equipped with B31 design codes, as discussed below. Pipe dimensions
tubular fittings that bring wellstream fluids to the produc- are set by the use of two nondimensional numbers: the
tion facilities. For onshore and near-shore applications, nominal pipe size (NPS) and Schedule number (Sch). NPS
pipelines are always the most recommendable option for is the dimensionless designator of standard pipe sizes and
transportation of fluids to the market. Pipelines are ubiq- provides a rough, round indication of its outside diameter

Table 22.1—Common Pressure Piping Specifications

Specification Pipe Type Size Range (NPS) Application

ASTM A53 Seamless/welded carbon steel 1/8 to 26 Ordinary use in gas, air, oil, water, steam

ASTM A106 Seamless carbon steel 1/8 to 48 High-temperature service

ASTM A369 Forged and bored carbon steel Custom High-temperature service
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

ASTM A335 Seamless carbon steel Custom High-temperature service

ASTM A333 Seamless/welded carbon steel 1/8 and larger Service requiring excellent fracture toughness at low temperature

ASTM A671 Electric fusion welded carbon steel 16 and larger Low-temperature service

ASTM A672 Electric fusion welded carbon steel 16 and larger Moderate-temperature service

ASTM A691 Electric fusion welded carbon steel 16 and larger High-temperature service

ASTM A312 Seamless/welded carbon steel 1/8 and larger Low- to high-temperature and corrosive service

API 5L, 5LX Seamless/welded carbon steel 1/8 and larger Line pipe, refinery, and transmission service
Source: [7].

Copyright ASTM International

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Chapter 22 n Transportation of Crude Oil, Natural Gas, and Petroleum Products 551

when measured in inches. Pipes with the same NPS share combining the first and second laws of thermodynamics.
the same outside diameter; in particular, pipes NPS 12 and Such a statement, for steady-state conditions and in its dif-
smaller have an outside diameter (measured in inches) ferential form, can be expressed as
greater than their NPS whereas pipes NPS 14 and larger
have an outer diameter (in inches) exactly equal to their dp vdv g
+ + dz + δlw = 0 (22.1)
NPS. The inside diameter of a pipe depends on the pipe wall ρ gc gc
thickness specified by a dimensionless Schedule number.
The Schedule number is a designation that varies from its where:
lowest at 5 to its highest at 160 (e.g., 5, 5S, 10, 10S, 20, 20S, δlw = compression energy (work) lost because of irrevers-
80, 80S). Schedules of stainless steel pipe are followed by ibilities,
the letter S, as per the guidelines of ASME B36.19M. The g = gravity acceleration, and
higher the Schedule number, the thicker and heavier the gc = unit-dependent mass/force conversion constant.
pipe is made. NPS 12 Schedule 30 has an outside diameter Equation 22.1 recognizes that no work is considered to
of 12.75 in. and an inside diameter of 12.09 in., whereas be done on or by the fluid in pipeline flow. This equation
NPS 12 Schedule 100 has an outside diameter of 12.75 in. is then integrated between two points to yield the modified
but an inside diameter of 11.064 in. In the United States, Bernoulli equation, or mechanical energy conservation
thickness designators STD for standard weight (low pres- statement, which relates elevation, pressure, and velocity
sure), XS/XH for extra strong/heavy (medium pressure), head changes to energy losses. Alternatively, the equation
and XXS/XXH for double extra strong/heavy (high pres- can be recast as a pressure gradient equation by normaliz-
sure) are not uncommon and are a legacy from the early ing each of its terms on a per-unit-length of pipe (dx) basis
years of the U.S. petroleum industry when the dimensional as follows [11]:
pipe system was known as iron pipe size (IPS). Diamètre
nominal (DN) is the size designator in the SI system of units  dp   dp   dp   dp  (22.2)
  =  +  + 
and is a dimensionless value numerically close to the pipe  dx T  dx  e  dx  a  dx lw
outside diameter expressed in millimeters. For thickness,
where:
the SI system uses the Schedule designator.
 dp  g dz
In terms of design and construction of piping systems,   = −ρ , or the pressure gradient due to pipe eleva-
the body of codes and standards for high-pressure pip-  dx  e gc dx
ing systems is contained within the ASME B31 pressure tion or potential energy changes,
piping code, which consists of several sections identified  dp  ρv dv
as “B31.X.” For example, ASME standard B31.1 applies   =− , or the pressure gradient due to acceleration
 dx  a gc dx
to steam piping systems, ASME standard B31.3 applies
or velocity (kinetic energy) changes, and
to process piping in petroleum refining and processing
plants, ASME standard B31.4 applies to onshore pipeline  dp  δlw
  = −ρ , or the pressure gradient due to irreversible
transportation of liquid hydrocarbons, and ASME standard  dx lw dx
31.8 applies to natural gas transmission and distribution energy losses.
systems. The understanding of these codes is necessary to Equation 22.2 allows rewriting the energy balance in
design a project that meets recognized regulations (codes, terms of the relative contributions that elevation, accelera-
standards, and specifications) for it to operate safely, obtain tion, and irreversible losses have to pipeline total pressure
required operational licenses, and even obtain insurance drop. Both elevation and acceleration terms represent pres-
for their operations [8–10]. sure losses of reversible nature because they are energy
The pipeline operator must select the most suitable and quantities retained by the fluid that can be converted back
cost-effective pipe type for the specified service condition. to pressure. Lost mechanical energy that cannot be trans-
Pipe material type is heavily dependent on operational envi- formed back into pressure represents an irreversible loss
ronment, with steel alloys representing the most common (δlw ). In a flowing system, flow irreversibilities (δlw ) consist
selection for any high-pressure application in the petroleum largely of primary or major losses (δlwf , losses due to fric-
industry. In turn, pipe dimensions are a function of the tional effects between the fluid and the pipe wall) and sec-
required transportation capacity and maximal allowable ondary or minor losses (δlwK , losses due to flow obstacles,
pressure of operation. The required transportation capacity presence of fittings, valves, elbows, and sudden changes
fixes the minimum allowable internal pipe diameter, and in diameter) where δlw = δlwf + δlwK . When considering
the maximum allowable pressure of operation fixes the flow in a straight section of pipe with no fittings where
minimum allowable pipeline thickness. Pipe design (i.e., irreversibilities are only generated by wall shear stress
the selection of the proper pipe NPS and Schedule) is thus (τ w ) between the moving fluid and the stationary pipe wall,
primarily based on the proper calculation of the minimal δlw = δlwf . For such a case, and for one-dimensional flow,
requirements of pipe diameter and thickness. These calcu- wall shear stresses are customarily and conveniently calcu-
lations are discussed in detail in this chapter for crude oil, lated in terms of dimensionless friction factors, as shown
petroleum products, and natural gas applications. in Eq 22.3:
 dp  δlw πd  ρv2  πd
22.3 Pipeline Flow Equations  dx  = − ρ dx = − τ w A = −  fF ⋅ 2 g  πd 2 / 4
lw  c 
Fluid flow equations through pipes are derived from ther-
2ρv2 ρv2
modynamic or energy balances. All fluid flow design equa- = − fF = − fM
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
gc d 2 gc d (22.3)
tions can be traced back to the same basic energy balance
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552 Petroleum Refining and Natural Gas Processing

Equation 22.3 embeds the definition of friction factor as From Eq 22.5b, it follows that pressure head losses
the dimensionless ratio of wall shear stress (τ w ) to the fluid can be calculated explicitly in terms of flow rate using the
inertial force (ρv2 / 2 gc). In this equation, fF represents the following generalized expression for liquid flow:
Fanning friction factor and fM the Moody friction factor
(fF = fM /4). hf = RL ⋅ q1/L n (22.6)
In most pipeline flow equations, the contribution of the
kinetic energy term to the overall energy balance is consid- where:
ered insignificant compared with the much larger magni- L
RL = pipe resistance to liquid flow, or RL = rL m , where rL is
tudes of the friction loss and the potential energy terms. By d
invoking this simplification, Eq 22.2 is integrated over the  f f 
the specific resistance to liquids  rL = F2 = M2  , m = 5, and
entire pipe domain (from x = 0, p = p1, and z1 = 0 to x = L, n = 0.5.  σ L 4σ L 
p = p2, and z2 = ∆H) to obtain In direct analogy to electrical circuit theory, pipe resis-
tance increases as pipe length increases and it decreases as
p2 L L
the pipe cross-sectional area increases. Specific resistances
∫ ρdp = − α∫ dx − β ∫ ρ dx
2
(22.4) capture the particularities of the fluid, flow, and pipe char-

p1
0

0

acteristics. It is clear from this development that pipe con-
friction elevation
ductivities and resistances are readily related through the
1
where: expression CL = n .
α = (32 ⋅ W 2 fF ) / ( π2 gc d 5 ) , RL
β = ( g / gc )(∆H / L ), and Equations 22.5 and 22.6, derived from fundamental
dz = (∆H / L ) ⋅ dx. principles and for which n = 0.5 and m = 5, are collectively
Equation 22.4 contains two density-dependent inte- known as the Darcy-Weisbach equations for frictional head
grals: the pressure integral at the left-hand side of the equa- loss in a horizontal pipe carrying a single-phase liquid.
tion and the elevation term contribution at its right-hand This equation can be extended to flow in inclined liquid
side. Because liquid and gas density behavior with pressure pipes by introducing the contribution of potential energy
is markedly different, different flow equations for the flow changes in Eq 22.4 in terms of elevation head (∆H ≠ 0).
of single-phase liquids and single-phase gases would result Upon integration,
from the integration of this energy balance.
qL = CL ⋅ ( p1 − p2 − γ L ⋅ ∆H )
n
(22.7)

22.4 Flow of Single-Phase Liquids or, equivalently,

For the flow of liquids or nearly incompressible fluids, both
density integrals in Eq 22.4 can be readily resolved. After hf = RL ⋅ q1/L n + ∆H (22.8)
integration, volumetric flow through a horizontal liquid
pipe (∆H = 0) can be shown to be dependent on the differ- The implementation of Eqs 22.5–22.8 to practical problems
ence of linear end pressures as follows: requires the calculation of friction factor coefficients, dis-
cussed in Section 22.5.
0.5
 π 2 gc  d 2.5
qL =   ⋅ ( p1 − p2 )0.5 (22.5a) 22.5 Flow of Single-Phase Gases
 32  ρ ⋅ fF ⋅ L
For the isothermal flow of gases, fluid density dependency
with pressure (ρ = ϕ ⋅ p) introduces a much stronger influ-
For liquid flow, it is customary to express flow equations ence of pressure into the makeup of the fluid flow equation.
in terms of pressure head (hf)—or the equivalent height Substitution of this relationship into both density-dependent
of the liquid fluid column for which the hydrostatic terms of Eq 22.4 yields, upon integration,
weight is equal to p1 – p2; that is, hf = ( p1 − p2 ) / γ L where
, 22.5a
γ L = ρ L ⋅ ( g / gc ), or the liquid specific weight. Equation 2 ( e s − 1)
alternatively becomes, when expressed in terms of a gener- p12 − e s p22 = αL (22.9)
ϕ s
alized short-form representation,
where s = 2ϕβL and ϕ = (SGg Mair ) / ( Zav RTav ) with α, β defined
qL = CL ⋅ h n
f (22.5b) previously for Eq 22.4. Equation 22.9 states the well-
known fact that the driving force for gas flow through pipe-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

lines is the difference of the squared pressures. This is an

where: unequivocal consequence of the now built-in dependency
n = 0.5 and of fluid density on pressure (ρ = ϕ ⋅ p) in the flow equation,
d 2.5
CL = pipe conductivity to liquids, or CL = σ L , which which was assumed inexistent in the derivation of the
fF ⋅ L
describes the dependency of pipe transport capacity on the liquid flow equations (ρ = const). In addition, Eq 22.9 also
properties of the fluid, flow, and pipe. σ L is a constant honors the ρ → p dependency during the integration of the
potential energy or elevation term of Eq 22.4 as originally
 2 π2 g 
 σL =  for which the numeric value is clearly unit performed by J.W. Ferguson in 1936 [12]. However, it is not
 32  uncommon to find that the contribution of potential energy
dependent: σ L = 3.15 ft0.5/s for the U.S. customary unit sys- is alternatively evaluated using a constant average gas
tem and σ L = 1.74 m0.5/s for the SI system of units. density (ρ av = ϕ ⋅ pav), which simplifies the integration of the
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Chapter 22 n Transportation of Crude Oil, Natural Gas, and Petroleum Products 553

e levation term of Eq 22.4 to yield the following simplified potential energy contribution is made using Ferguson’s
version of the gas flow equation for inclined pipes: approach, Eq 22.9 is used to derive
2 qGsc = CG ⋅ ( p12 − e s p22 )
n
p12 − p22 = αL + 2βLϕ ⋅ pav
2
(22.10) (22.16)
ϕ
or,
For horizontal flow, ∆H = 0, s = β = 0, ( e s − 1) / s → 1 and
both design equations for gas flow naturally collapse to p12 − e s p22 = RG ⋅ qGsc
1/ n
(22.17)
the same expression. In this case, both expressions can be
solved for the gas flow rate evaluated at standard condi- where the definitions of CG in Eq 22.12 and RG in Eq 22.13
tions (qGsc) by making the transformations W = ρ sc ⋅ qGsc and must be slightly modified to account for the concept of the
ρ sc = ( psc SGg Mair ) / ( R ⋅ Tsc ) to obtain equivalent pipe length (Le):
0.5
 π 2 gc R  Tsc / psc d 2.5
qGsc = CG ⋅ ( p12 − p22 )n (22.11) CG =   0.5 0.5 0.5
(22.18)
 64Mair  (SGGTav Zav ) fF Le
where n = 0.5 and CG is the pipe conductivity to gas, defined
as and,

 π 2 gc R 
0.5 Le
Tsc / psc d 2.5 RG = rG (22.19)
CG =   0.5 0.5 0.5 (22.12) dm
 64Mair  (SGgTav Zav ) fF L
In Eqs 22.18 and 22.19, pipe equivalent length is a function
Pipe conductivity captures the dependency of the flow of the s-elevation parameter defined above through the fol-
capacity of the pipe to gas as a function of friction factor, lowing relationship:
pipe geometry, and fluid properties. Equation 22.11 can
( e s − 1)
also be recast in terms of pressure loss in the following Le = L (22.20)
generalized short-form representation: s
where:
p12 − p22 = RG ⋅ qGsc
1/ n
(22.13)  SGG Mair   g 
s = 2ϕβL = 2     ∆H.
where:  Zav RTav   gc 
RG = pipe resistance to gas,
L In Eq 22.20, Le = L for horizontal pipes [( e s − 1) / s → 1 as s →
RG = rG m , 0]. For uphill flow, Le > L because ∆H > 0 and s > 0. For
d
rG = pipe specific resistance to gas, downhill flow, Le < L because ∆H < 0 and s < 0. In customary
SGGTav Zav  psc 
2
 SGG ⋅ ∆H 
rG = fF   , field English units, s = 0.0375   . The implementa-
σ2G  Tsc   Zav ⋅ Tav 
m = 5, and tion of Eqs 22.11–22.19 to practical problems in natural gas
n = 0.5. pipeline engineering requires the calculation of friction fac-
64M tor coefficients to be discussed next.
In this relationship, σ2G = 2 air , a dimensional con-
π gc R
stant for which the ultimate numeric value is dependent on
the choice of units for the equation. For customary U.S.
22.6 Friction Factor Calculations
Frictional pressure losses are a direct function of wall shear
field units, σG = 2,818 SCF·ft0.5 R-0.5 in-0.5 if qGsc (SCF/D), L (ft),
stresses. Frictional losses are thus calculated in terms of
d (in.), p (psia), and T (R). For SI units, σG = 574,901 sm3/
the prevailing shear force (i.e., shear stress multiplied by
K0.5 if qGsc (sm3/d), L (m), d (m), p (kPa), and T (K). Again,
pipe wall surface area) divided by the flow cross-sectional
gas pipe conductivities and resistances are clearly related
1 area as shown in Eq 22.3. Friction factors are the dimen-
through the expression CG = n . sionless quantities customarily used in the estimation of
RG
For flow in inclined gas pipes, Eqs 22.9 and 22.10 are these wall shear stresses and are defined as the ratio of
rearranged to derive two versions of the same gas flow shear stress (τ w ) to kinetic energy (ρv2 / 2 gc),
equation. If the potential energy evaluation is made based τw
on the calculation of an average gas density value for the fF = (22.21)
ρv2 / 2 gc
entire pipe, Eq 22.10 can be used to show
n for the case of the Fanning dimensionless friction factor.
 g  Dimensional analysis of the equations of change applied to
qGsc = CG ⋅  p12 − p22 − ϕ ⋅ pav
2
∆H  (22.14)
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

 gc  flow in circular pipes demonstrates that such a definition
of friction factor is directly dependent on Reynolds num-
or, ber for fully developed flows [13]. Reynolds number is the
dimensionless parameter that quantifies the ratio of inertia
g
p12 − p22 = RG ⋅ qGsc
1/ n
+ ϕ ⋅ pav
2
∆H (22.15) forces to viscous forces and is defined as
gc

where the definitions of CG and RG remain the same as for Inertia Forces ρv2 / d ρvd vd 4q
Re = = = = = (22.22)
the horizontal case. Alternatively, when the evaluation of Viscous Forces µv / d 2 µ υ πdυ
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554 Petroleum Refining and Natural Gas Processing

where: have been shown to be dependent not only on Reynolds

µ = fluid dynamic viscosity and numbers but also on relative pipe roughness (e/d) [13].
υ = fluid kinematic viscosity. In this flow domain, dimensionless friction factors must
When viscous forces dominate over inertia forces be calculated from experimental data of pressure drop
(Re < 2,100), flow is said to be laminar and friction factors versus flow rates in pipes. In 1944, experimental results
can be readily calculated from the analytical solution to the on pipe friction available at the time were masterfully
flow equation for circular pipes as consolidated by Lewis F. Moody in the form of the chart
reproduced in Figure 22.2. Since then, Moody’s chart
fF = 16/Re (22.23) has become an essential reference in pipe flow calcula-
tions. Moody’s chart is based on the implementation of
for the Fanning friction factor or, equivalently, the Darcy-Weisbach equation for frictional loss (Eq 22.6)
written in terms of Moody friction factors. Before the
fM = 64/Re (22.24) publication of Moody’s chart, the smooth pipe, rough pipe,
and transition flow behavior in the turbulent zone had
for the Moody friction factor. If one substitutes Eq 22.23
been fully documented, but the selection of proper values
into the Darcy-Weisbach liquid flow equation (Eq 22.6), the
of relative pipe roughness (e/d) for pipe materials of com-
result is the well-known Poiseuille’s law for laminar liquid
mercial interest had not been established. Moody’s paper
flow:
made the Darcy-Weisbach equation more readily appli-
cable to engineering problems of interest not only because
p1 − p2 128 ⋅ µ L L it aptly summarized the pipe friction data available at
hf = = ⋅ qL (22.25)
γL π ⋅ gc ⋅ γ L d 4 the time but also provided engineering guidance for the
selection of appropriate values of relative pipe roughness
An analogous expression is not extended to natural gas flow (e/d) for pipe materials of commercial application such as
because gas pipe flows are highly turbulent due to the low riveted steel, concrete, cast iron, and wrought iron. Figure
viscosity of the gaseous phase and exhibit a more signifi- 22.2 provides Moody f values directly; thus, to calculate
cant dependency of density on pressure, which is ignored the associated “Fanning” friction factors, the equivalency
by Eq 22.6. fF = fM /4 must be used.
When inertia forces overwhelm viscous forces, flow For computer applications, Figure 22.2 has been fit-
is said to be turbulent or transitional (Re > 2,100). For ted to a myriad of empirical equations that numerically
fully developed turbulent flow conditions, friction factors reproduce the data in the Moody diagram. One of the most

Figure 22.2—Moody friction factor (fM) chart for the Darcy-Weisbach equation. Source: [14].
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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AST-MNL58-11-0801-022.indd 554 3/12/13 3:18 PM

Chapter 22 n Transportation of Crude Oil, Natural Gas, and Petroleum Products 555

fitting choices for this purpose is the use of the Colebrook The left-hand side of these equations, when written as
formula [15]: 1 2
F= = , is known as the transmission factor of the
fF fM
1 e/ d 2.51  pipe (F).
= −2.0 log10  + 
fM  3.7 Re f
 
M
22.7 Specialized Equations for Liquid Flow
 2e 18.7  As already established, pipeline equations for liquid flow
= 1.74 − 2.0 log10  +  (22.26a)
 d Re f can be conveniently written in the following general short-
 M 
form representation, previously presented as Eq 22.6:

It is to be noted that Colebrook’s equation preceded the for- L 1/ n

mulation of Moody’s diagram. Moody’s chart was actually hf = RL ⋅ q1L/ n = rL ⋅ qL (22.6)
dm
drawn on the basis of Colebrook’s equation, which com-
bined experimental results of studies of turbulent flow in This generalized expression captures the dependency of
smooth pipes and rough pipes and allowed for a transition pressure head loss on total pipe resistance to liquid flow
zone between the two limiting behaviors. Therefore, Cole- (in terms of length, diameter, and specific resistance rL)
brook’s expression is bounded by (and thus can be collapsed and flow rate. This equation requires the definition of the
to) these two widely known limiting pipe friction behaviors: appropriate flow exponent (n) and diameter exponent (m)
the smooth pipe law (e/d → 0) shown as Eq 22.26b and the and the calculation of pipe specific resistance (rL).
Reynolds-independent rough pipe or fully turbulent equa- The most rigorous approach for the calculation of
tion (Re → ∞) shown as Eq 22.26c. frictional losses for single-phase incompressible flow of
fluids in pipelines is the application of the Darcy-Weisbach
equation, which is derived from first principles and for
1  2.51  which m = 5 and n = 0.5. However, this entails the calcu-
= −2.0 log10  
fM  Re f lation of friction-factor dependent rL values by using the
 M 
Moody chart or any of its associated empirical equation
 Re 
= 2.0 log10   (e/d → 0) (22.26b) fittings. This calculation invariably requires the availabil-
 2.51 ⋅ 1 / f ity of a good estimate for pipe roughness and an iterative
 M 
procedure for the calculation of pipe diameter or flow rate.
Some users would rather avoid this. This is why, despite the
1 e/ d stated generality of the Darcy-Weisbach equation, the use
= −2.0 log10  
fM  3.7  of alternative, iteration-free, empirical pressure loss equa-
tions continues to be common. These empirical equations
 3.7 d 
= 2.0 log10   (Re → ∞ ) (22.26c) are always much more limited in terms of range of applica-
 e  bility; however, they remain popular in many applications
because of the shear convenience of their ease of use and
The point at which transition from smooth pipe law to fully simpler formulation. Another factor that contributes to the
turbulent or rough pipe law occurs can be determined by familiarity and repeated use of empirical substitutes is that
equating the above expressions to obtain many were widely available even before the development
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

of the Moody diagram, and many successful designs have

18.574 d  3.7 d  since been made on their account.
Re = log10   (22.26d) Table 22.2 lists the most commonly used equations for
e  e 
liquid flow, their inherent assumption for friction factor
calculation, and the resulting exponents n and m in terms of
A minor drawback in the implementation of the Colebrook
the generalized functional form. The Darcy-Weisbach equa-
equation is that it expresses the friction factor as an implicit
tion is the first equation shown in Table 22.2. As previously
function of itself, which requires the implementation of
demonstrated, the Darcy-Weisbach equation collapses to
iterative equation-solving procedures. Although this is no
Poiseuille’s law for laminar flow conditions, which is shown
longer a significant concern given the computational power
as the second entry in the table. All equations for liquid
available nowadays, several explicit friction factor expres-
flow can be written in terms of the generalized functional
sions have been also proposed. One of such expressions is
form shown at the top of Table 22.2, including the empirical
Chen’s friction factor equation [16], claimed to present a
choices. Empirical correlations just replace Moody-based
maximal absolute deviation of 0.4651 % when compared
friction factor calculations by alternative, simpler expres-
with Colebrook’s equation and reproduced as follows:
sions of friction factor, which are limited in their scope.
By far, one of the most widely known empirical equa-
1 = −2.0 log  e
−
5.0452  ( e / d )1.1098 5.8506 
log  +
tions for liquid flow is the Hazen-Williams correlation.
10  The Hazen-Williams correlation was originally developed
fM  3.7065d Re  2.8257 Re 0.8981 
for the study of the flow of water in turbulent flow condi-
(22.27) tions [17] and provides an empirically derived relationship
between water volumetric flow and pressure (or head)
For the calculation of Fanning friction factors, the equiva- losses. Table 22.2 shows the implied friction factor func-
lency 1 = 1 ⋅ 1 must be substituted into these equations. tional relationship when the Hazen-Williams correlation
fM 2 fF is implemented. In this expression, the parameter CHW is
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556 Petroleum Refining and Natural Gas Processing

Table 22.2—Summary of Specialized Equations for Liquid Flow

L
hf = RL ⋅ qL1/ n = rL ⋅ qL1/ n [Eq 22.6]
dm

Equation Friction Factor rL n m

fF f
Darcy-Weisbach (generalized) Moody chart rL = = M 0.50 5.0
σL2 4σL2
16 128 ⋅ µ L
Poiseuille’s law (laminar flow) fF = rL = 1.0 4.0
Re γ L ⋅ π ⋅ gc
κHW d 0.13 1
Hazen-Williams fF = rL = 0.54 4.87
1.852
C HW qL0.148 σ2L ,HW ⋅ C HW
1.852

κM ⋅ nM2 nM2
Manning fF = rL = 0.50 5.33
d 0.33 σ2L ,M
CHW = Hazen-Williams dimensionless roughness coefficient and nM = Manning dimensionless roughness parameter;
CHW = 150, and nM = 0.009 for polyvinyl chloride (PVC); CHW = 140 and nM = 0.011 for smooth metal pipes and
cement-lined ductile iron; CHW = 130 and nM = 0.014 for new cast iron and welded steel; CHW = 120 and nM = 0.016
for wood and concrete; CHW = 110 and nM = 0.017 for clay and new riveted steel; CHW = 100 and nM = 0.020 for
old cast iron and brick; and CHW = 80 and nM = 0.035 for badly corroded cast iron [18]. Values above assume the
flow of water. Suggested values of CHW for refined petroleum products as a function of temperature have also
been reported [19]. κHW , κM = unit-dependent constant in the friction empirical equation. κHW = 46.9334 and κM =
46.2388 for d (ft), qL (ft3/s); κHW = 33.977 and κM = 105.6732 for d (in.), qL (ft3/s); and κHW = 32.3045 and κM = 31.154
for SI units. σL , σL ,HW , and σL ,M = unit-dependent constants for specific resistance calculations. For qL (ft3/s), L (ft), d
(ft), σL = 3.15, σL ,HW = 0.4598, and σL ,M = 0.46324. For qL (ft3/s), L (ft), d (in.), σL = 6.3148∙10-3, σL ,HW = 1.08335∙10-3, and
σL ,M = 6.143∙10-4. For SI units, σL = 1.74, σL ,HW = 0.30614, and σL ,M = 0.31174.

the Hazen-Williams dimensionless roughness coefficient, ingly to account for different fluid types and even viscosity
which attempts to capture the change in roughness associ- changes with temperature. Albeit its significant limitations,
ated with different pipe materials. Table 22.2 shows some the Hazen-Williams correlation remains popular in the
typical values of CHW for common pipe materials. There is design of water hydraulic systems in the United States, and
no explicit dependency of friction factor on Reynolds num- its use has been documented and recommended even for
ber; thus, the resulting calculations are arguably insensitive calculations of pressure drop for refined petroleum prod-
to fluid properties and fluid type. In practical applications, ucts such as gasoline, kerosine, and diesel with properly
the selection of the Hazen-Williams roughness coefficient tuned values of CHW (see, e.g., [18,20]).
(CHW) has largely relied on the user’s experience with the Figure 22.3 presents a friction factor prediction com-
system under investigation and has been tuned accord- parison between the Hazen-Williams correlation versus

0.01

0.009 NPS 18 Sch 40

Hazen-Williams d = 16.876 in
0.008 (CHW = 100)
υ = 10 cSt
Fanning Friction Factor

0.007
Colebrook
e = 0.0018 in
0.006 Carbon steel

0.005
Hazen-Williams
(CHW = 120)
Hazen-Williams
0.004 (CHW = 140)
Smoot
h pipe
law
0.003

0.002
1 10 100
qL (ft3/s)

Figure 22.3—Friction factor comparison for the specialized liquid equations.

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

Copyright ASTM International

AST-MNL58-11-0801-022.indd 556 3/12/13 3:18 PM

Chapter 22 n Transportation of Crude Oil, Natural Gas, and Petroleum Products 557

the more rigorous Colebrook prediction for the case of the ized short-form representation previously presented as
transportation of a petroleum product (kinematic viscos- Eq 22.13:
ity = 10 Sct) through a NPS 18 Sch 40 carbon steel pipe
(e = 0.0018 in.). This figure reveals that a Hazen-Williams L 1/ n
p12 − p22 = RG ⋅ qGsc
1/ n
= rG ⋅ qGsc
coefficient of CHW = 120 is able to approximately capture dm (22.13)
the overall friction factor behavior with increasing flow
rate with a somewhat underestimated slope at low flow Table 22.3 presents a list of well-known choices available
rates. Other CHW choices have the potential of grossly over- for gas pipe calculations, along with their associated defini-
estimating or underestimating friction losses, as shown. tions of n, m, and pipe specific resistance (rG). Average
This figure demonstrates that whether Hazen-Williams compressibility factors (Zav) in this table are calculated as a
predictions can be trusted or not is basically dependent on function of pav and Tav using any standard gas compressibil-
whether the user of the equation can rely on experience or ity factor correlation. A popular choice for the calculation
expert advice for the proper value of CHW that should be of the average pipeline pressure (pav) in gas systems is to use

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
used. The user could potentially reconstruct a plot such as 2  p3 − p23 
the expression pav =  12  or any of its equivalent ver-
Figure 22.3 for the particular application and “tune” the 3  p1 − p22 
value of CHW to the one that best captures the overall Cole-
sions. This pav expression results from applying the stan-
brook trend. This would entail some iterative calculations
and beg the question of why Darcy-Weisbach was not used  1 V 1 L 
in the first place.
dard average pressure definition  pav =
 V ∫0
pdV =
L ∫0
pdx 

The Manning correlation is another correlation to the expected parabolic pressure profile for isothermal
empirically developed for the study of flow of liquids
gas pipes  p2 ( x) = p12 − ( p12 − p22 )  . In turn, values of Tav are
x
in open channels that became popular in the late 19th
century [21]. It continues to be widely used in the design  L 
of water sewer systems—where fluid channels do not typically taken as the arithmetic average between the pipe
typically flow at full capacity [17]. For the Manning cor- inlet and outlet temperatures for conditions when expected
relation, n = 0.5 (flow exponent) and m = 5.33 (diameter temperature changes in the pipe are not significant. Please
exponent) whereas rL is made a function of a dimensional refer to Section 22.13 for a discussion about the additional
constant and a material-dependent dimensionless rough- calculations required when fluid temperatures are expected
ness coefficient (nM) alone, as shown in Table 22.2. In to significantly change along the pipe.
Manning’s expression, the dimensionless parameter nM The most rigorous approach for the calculation of
has the same purpose as the CHW parameter had for the frictional losses in single-phase compressible fluid flow in
Hazen-Williams equation, which is to attempt to cap- pipelines is the application of the general gas equation—
ture the change in roughness associated with different shown first in Table 22.3 and for which m = 5 and n = 0.5.
pipe materials. One of its shortcomings is that it offers The general gas equation, derived from first principles, cap-
a flow-rate independent friction factor calculation; thus, tures the dependency of squared pressure loss with respect
it would display as a straight horizontal line in Figure to gas flow rate and total pipe resistance flow on the basis
22.3. Interestingly, Manning and Hazen-Williams correla- of length and diameter, and calculates specific resistances
tions were used by the reviewers of Moody’s paper [14] (rG) rigorously from Moody’s chart. The implementation
when evaluating the merits of the then recently proposed of Moody’s friction factor equations requires an iterative
Moody’s method—an observation that highlights the numerical procedure given the dependency of friction fac-
deeply engrained reliance on such empirical correlations tor on flow rate and pipe diameter.
before the publication of Moody’s chart. Other empirical Since the early 1900s, and much before the formula-
flow equations for liquids are also available for special- tion of Moody’s diagram, many empirical approaches were
ized purposes. For example, Menon presents a summary already in place to describe gas flow [22]. Many of these
of liquid empirical equations used for liquid pipeline flow equations, and their successors, were formulated on the
calculations that includes the Shell-MIT equation for the basis of matching field data obtained from operating or
calculation of pressure drop in heavy crude oil and heated experimental gas pipeline systems. One noteworthy exam-
liquid pipelines, the B. Miller equation for the calculation ple is the Weymouth equation, developed by Thomas R.
of pressure losses in crude oil pipelines, and the T.R. Aude Weymouth in the early 1910s by matching compressed air
equation for the calculation of head losses in pipelines test data flowing through small diameter pipes (0.9–11.8
transporting refined petroleum products [20]. All of these in.) at low pressures [23]. Decades later, in the 1940s, the
equations can be written in terms of the general liquid Panhandle-A equation (the “original” Panhandle equation)
pipeline functional form, h = r L ⋅ q1/ n , where the appro- was proposed by matching field pressure drop test data
f L L
dm
priate values of rL, n (flow exponent), performed in 24-in. transmission lines operated by the
and m (diameter
Panhandle Easter Pipe Line Company [24,25]. Panhandle
exponent) must be defined.
equations were developed with the intention of proposing
flow equations suitable for larger diameter pipes because
the Weymouth equation was known to overestimate pres-
22.8 Specialized Equations for Gas Flow sure losses for those systems. The Panhandle-B equa-
As before, the fundamental difference among specialized tion (the revised or “modified” Panhandle equation) was
formulas available for natural gas flow resides in how fric- published in 1952 when more operating data at higher
tion factors are evaluated. These gas equations for pipe pressures and flow rates became available from other
flow can be conveniently written in terms of the general- Panhandle pipelines [24,25]. Friction factor assumptions
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558 Petroleum Refining and Natural Gas Processing

Table 22.3—Summary of Specialized Equations for Gas Flow

L
p12 − p22 = RG ⋅ qGsc
1/ n
= rG ⋅ qGsc
1/ n
[ Eq 22.13 ]
dm
Equation Friction Factor rG n m
2
SGgTav Z av p 
General gas equation Colebrook equation rG = fF  sc  0.50 5.0
σG2  Tsc 
2
SGgTav Z av  psc 
Weymouth κW rG =   0.50 5.333
fF = σG2 ,W  Tsc 
d 1/ 3
2
κPA SGg0.854Tav Z av  psc 
Panhandle-A (original panhandle) fF = 0.1461
rG =   0.5394 4.854
 qGsc ⋅ SGg  σ1G.854
,PA  Tsc 
 
 d 
2
Panhandle-B (modified panhandle) κPB SGg0.961Tav Z av  psc  0.510 4.961
fF = 0.03922
rG =  
 qGsc ⋅ SGg  σ1G.961
,PA  Tsc 
 
 d 
2
1  Re fF  SGgTav Z av p 
AGA (partially turbulent) = 4FD log10   rG = fF  sc  0.50 5.0
fF  1.41  σG2  Tsc 
 
 3.7 d  2
1   SGgTav Z av p 
AGA (fully turbulent) = 4.0 log10  e 
rG = fF  sc  0.50 5.0
fF σ 2
G  Tsc 
κW , κPA , κPB = unit-dependent constant in friction empirical equations. κW = 0.008 for d (in.) or 0.002352 for d (m); κPA = 0.01923 for d (in.),
q (SCF/D) or 0.01954 for d (m), q (sm3/d); κPB = 0.00359 for d (in.), q(SCF/D) or 0.00361 for d (m), q (sm3/d). σG, σG ,W , σG ,PA , σG ,PB = unit-dependent
constants for specific resistance calculations. For qGsc (SCF/D), L (ft), d (in.), p (psia), T (R): σG = 2,818; σG ,W = 31,508; σG ,PA = 44,400; σG ,PB = 58,328. For
qGsc (SCF/D), L (miles), d (in.), p (psia), T (R): σG = 38.784; σG ,W = 433.618; σG ,PA = 435.98; σG ,PB =736.77. For SI units in qGsc (sm3/d), L (m), d (m), p(kPa),
T (K): σG = 574,901; σG ,W = 11.854∙106; σG ,PA =13.656 ∙106; σG ,PB =13.196∙106.

of these popular gas equations are presented in Table 22.3. when compared against the original smooth pipe law.
Weymouth, Panhandle-A, and Panhandle-B represent an A second AGA friction factor estimate is obtained from
enduring legacy of this early modeling period and they the fully turbulent (rough pipe) form of the Colebrook
have outlived many of their empirical predecessors and equation (i.e., Eq 22.26c for Re → ∞). This is known as
remain the most well-known equations for gas pipeline the AGA fully turbulent equation and is shown as such in
flow. These equations continue to be used nowadays for Table 22.3. Friction factor calculations in fully turbulent
applications clearly far beyond the scope of their origi- regimes are known to be Reynolds independent and solely
nal formulation. Many users like the simplicity of their dependent on pipe roughness; thus, the fully turbulent
formulation and their noniterative nature. Many others AGA equation is frequently recommended for the design
cannot justify their use given the availability of rigorous of a high-flow system, especially when roughness esti-
approaches (i.e., the Colebrook equation coupled with the mations are reliable. However, given its implicit nature,
general gas flow equation) and the computer power to the application of the partially turbulent AGA equation
implement it. requires as much iterative work as the direct application
In the 1960s, the American Gas Association (AGA) of the Colebrook equation does, and it would additionally
proposed the AGA equation, which uses the general gas require the empirical estimation of a drag factor based on
equation with simplified, limiting forms of the Colebrook AGA guidelines [26–28].
equation [26–28]. The AGA method calculates two fric- Empirical correlations, albeit convenient to use, are
tion factor estimates using Colebrook’s limiting behav- limited in their scope of application and should be used
iors (i.e., modified versions of Eqs 22.26b and 22.26c) with caution. Figure 22.4 displays the typical performance
and selects the highest value between the two. A first of gas equations in terms of their Fanning friction factor
friction factor estimate is calculated on the basis of the predictions. This plot is analogous to the one presented by
empirically modified smooth pipe approximation (i.e., Boyd (1983) in terms of transmission factors [29]. This fig-
Eq 22.26b for e/d → 0) via the introduction of a “drag ure displays friction factor predictions from all empirical
factor” (FD) multiplier. This smooth pipe law empirical correlations in Table 22.3 and compares them against the
modification was renamed the AGA partially turbulent more rigorous Colebrook prediction for the case of trans-
equation and is shown as such in Table 22.3. AGA’s ver- portation of a natural gas (SGG = 0.70 and µ g = 0.012 cP)
sion of the smooth pipe law uses a slightly different through a NPS 18 Sch 40 carbon steel pipe (e = 0.0018 in.).
numerical coefficient within the logarithmic argument, It is important to keep in mind that, in Figure 22.4, all mod-
as shown in Table 22.3, combined with the use of empiri- els are supposedly predicting the same variable—namely
cal drag factors (FD), which can take values from 0.90 to
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
friction factor—however, predictions can be seen to be
0.97—effectively increasing friction factor estimations wildly different from each other. For example, Weymouth
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Chapter 22 n Transportation of Crude Oil, Natural Gas, and Petroleum Products 559

0.0050

NPS 18 Sch 40
0.0045 d = 16.876 in
µg = 0.012 cp

Sm
oo
Colebrook SGg = 0.70

th
0.0040 e = 0.0018 in

pip
e
Carbon steel
Fanning friction factor

0.0035
Weymouth

0.0030
Panhandle-A AGA fully-turbulent
(e = 0.0018 in)
0.0025

0.0020 Panhandle-B

0.0015
1 10 q Gsc - 10-6 (SCF/D) 100 1000

Figure 22.4—Friction factor comparison for the specialized gas equations.

values tend to obviously overestimate friction losses at high high flow rates, the Panhandle-B prediction would have to
flow rates, which would lead to conservative pipe designs. be “displaced” upward by multiplying it with a suitable fac-
For some users, this friction overestimation by Weymouth tor. This is the effect accomplished by the introduction of
is not necessarily seen as a problem but rather as a poten- “efficiency factors” into gas flow equations.
tially desirable built-in safety factor in high-volume gas The concept of efficiency factors (Ef) has found wide-
piping design. The flow-rate independent nature of the spread use in the implementation of gas specialized equa-
Weymouth friction factor prediction identically matches tions of empirical nature. These parameters empirically
the behavior of fully turbulent predictions of the Colebrook adjust transmission factor values with the ultimate pur-
equation but 1only /6
for pipes with roughness equaling pose of matching field observations by increasing the effec-
e = 3.7 ⋅ d ⋅ 100.25⋅d / κW , which corresponds to e = 0.0021 in. tive friction factor embedded into the gas equation. Tuned
for the scenario presented in Figure 22.4—a larger value 1
transmission factors become F = Ef ⋅ and effective fric-
than expected for carbon steel pipes. In direct contrast to fF
fF
the flow rate independent nature of the Weymouth prediction factors hence become ( fF ) eff = 2 . From this defini-
tion, the Panhandle-A (original Panhandle) equation tends Ef
to rather track the smooth-pipe law prediction and thus tion, larger effective friction factors and pressure losses are
does a better job at lower Reynolds numbers (partially tur- generated by the gas equations for any Ef < 1 (note that the
bulent region) at which friction factors tend to be less depen- use of Ef = 0.7071 actually doubles the friction factor pre-
dent on pipe roughness. While Weymouth is able to track diction of the equation). Throughout the years, the success-
fully turbulent behavior and Panhandle-A smooth-pipe ful applications of empirical gas flow equations to field
behavior, the Panhandle-B (modified Panhandle) equation problems have been largely tied to this artificial tuning of
does quite a poor job of mimicking any Colebrook trend. This their prediction capabilities via the use of these adjustable
“modified” Panhandle equation was intended to be applica- factors. In Figure 22.4, all calculations assumed Ef = 1 for
ble to high-flow pipes, which results in its flatter slope in all equations. However, the implementation of adjustable
Figure 22.4. Because of these different slopes and Reynolds and less-than-unity Ef values (Ef < 1) would force the
dependencies, Panhandle-A always predicts larger friction upward displacement of the empirical curves in Figure
factors than those of Panhandle-B when used at low to mod- 22.4, which with careful selection can result in making
erate flow rates. At high flow rates, the situation reverses. them more closely follow Colebrook’s predictions and
This Panhandle crossover point takes place at flow rates trends. This discussion is analogous to the one pertaining
9.35
κ   d  the “proper” selection of CHW values in the empirical Hazen-
equal to qGsc =  PA    , above which Panhandle-B Williams liquid equation in the sense that values of Ef
 κ PB   SGg  (empirical gas equations) and CHW (liquid Hazen-Williams
would predict larger, higher friction factors, although still equations) need “tuning” for the equation to match field
significantly lower than Colebrook’s and Weymouth’s in data or Colebrook’s trends, or both. However, different
Figure 22.4. To bring Panhandle-B friction factor predic- equations would require the use of different Ef values to
tions in line with fully turbulent Colebrook predictions at match a common Colebrook or field data target. Such Ef
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

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AST-MNL58-11-0801-022.indd 559 3/12/13 3:18 PM

560 Petroleum Refining and Natural Gas Processing

values are thus likely to be rate dependent. When evaluat- mechanical strength required for the pipe to safely oper-
ing empirical equations, a comparison plot analogous to ate. The calculation of pipe internal diameter that is based
the one presented in Figure 22.4 can be used as a useful on the use of the flow equations discussed above com-
tool for assessing the suitability of an empirical equation bined with the estimation of the minimum wall thickness
for a given particular application. The reliability of an provide all of the information engineers need to select the
empirical equation can be measured in terms of how well proper NPS and schedule of the required pipe for the given
it is able to track the corresponding Colebrook prediction application.
for the expected transportation volumes and pipe sizes. It For a safe operation, pipe walls must be made thick
is important to point out that the direct use of the general enough so that pipeline stresses do not to exceed the
gas equation coupled with the Colebrook equation would minimal yield strength of its construction material. In
not be completely free of uncertainty because proper val- other words, pipes must be designed with sufficient
ues of roughness of a pipe need to be determined and they mechanical strength so they can withstand the stresses
are known to evolve with time. associated with their operating environment and hence
Beyond the popular Weymouth and Panhandle equa- avoid initiation of fractures that can lead to pipe failure.
tions, many other empirical gas flow equations have been Conditions that lead to pipeline failure include excessive
proposed. Menon presents a summary of other empirical internal pressure, thin pipe walls, and low yield strength
equations that have been proposed for gas pipeline flow, of the pipeline manufacture material. Relating these three
such as the IGT, Splitzglass, Mueller, and Fritzsche equa- variables and finding the safest operational combination
tions [30]. All of these equations can be similarly written in among the three is the key driving force behind pipe
L 1/ n stress analysis.
terms of the same generalized short form p12 − p22 = rG m ⋅ qGsc
d In stress analysis, pipes are visualized as cylindrically
once the appropriate values of rG, n (flow exponent), and m shaped containers. The stress state in these containers is
(diameter exponent) have been defined. characterized by the stress tensor (S), written, in cylindrical
coordinates, in terms of a radial (r), axial (z), and circum-
22.9 Pipeline Design: NPS and Schedule ferential (θ) component. In the analysis of failure due to
Selection excessive internal pressure, the initiation of cracks is said to
Liquid and gas equations can be written in an analogous be controlled by the magnitude of the largest component of
short-form notation, as shown by Eq 22.28: the internal-pressure-induced stress tensor (S). The stress
component recognized to be the largest in magnitude is the
L 1/ n one that acts on the circumferential or tangential direction,
∆p* = RK ⋅ q1K/ n = rK ⋅ qK (22.28) which is known as the hoop stress (Sh). The hoop stress
dm
derives its name from being the component of the stress
In Eq 22.28, the subscript K denotes either L for liquids tensor that directly counteracts the bursting force of the
or G for gases and Δ p* = ( p1 − p2)/γL = hf for liquids or Δ p* = internal pressure (Pin), just as steel hoops prevent wooden
p12 − p22 for gases. The internal diameter requirement of a barrels from bursting. In a free-body diagram of a half
pipeline can thus be calculated as segment of the cylindrical body, hoop stresses are found at
both ends of the cylindrical cavity acting perpendicularly

1/ m to the cross-sectional pipe thickness areas (t ⋅ L) found
q1/ n 
d =  rK ⋅ L ⋅ K *  (22.29) along the pipe axis. When the hoop stress force component
 ∆p 
[Sh ⋅ 2(t ⋅ L )] counteracts the bursting force created by the
internal pressure [Pin ⋅ ( do ⋅ L )], the following relationship
Equation 22.29 demonstrates that the pipeline internal can be written:
diameter requirement is a function of desired transporta-
tion capacity (qK), available pressures (Δp*), transportation pin ⋅ do
distance (L), and specific pipe resistance (rK). For rigorous Sh = (22.30)
2⋅t
calculations, rK is an implicit function of diameter through
the friction factor; thus, this calculation would require an where
iterative procedure unless a suitable diameter-independent t = pipe wall thickness,
empirical correlation is used for the calculation of specific do= pipe outside diameter, and
resistance (rK). Note that flow and diameter-dependent Pin = pipe design or internal pressure.
friction-factor empirical frictions do not necessarily lead Equation 22.30 is known as the thin-wall approxima-
to flow and diameter-dependent specific-resistance calculation for the hoop stress in cylinders and is only valid when
tions because of the adjusted values of n and m (for exam- the diameter of the cylinder (pipe) is several times larger
ple, refer to the simplified forms of the Hazen-Williams than the wall thickness—at least 10 times, d/t > 10. When
and Panhandle equations in Tables 22.2 and 22.3). Because pipes cannot be considered thin-walled, a more rigorous
pipeline diameters come in discrete finite sizes, the nearest form of the three stress components, known as Lamé’s
larger pipeline internal diameter is selected from a table of equation, needs to be considered [8].
available nominal sizes. This selection needs to take into For safe pipeline operation, the largest stress compo-
consideration the required pipe wall thickness, which is nent in the pipe (hoop stress, or Sh) must be found below
discussed below. the specified minimum yield strength of the pipe material
Although pipe internal diameter is a direct function p d
(SMYS or Sy; i.e., Sy > Sh = in o ). This limitation can be
of its desired transportation capacity, the selection of wall 2t
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

thickness (and thus pipe schedule) is based on the minimal restated in terms of the minimum value of wall thickness
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Chapter 22 n Transportation of Crude Oil, Natural Gas, and Petroleum Products 561

required for any given value of minimum strength Sy, as lines is made location dependent and primarily a function
follows: of how close the pipeline is found to structures with sig-
nificant human occupancy. ASME-recommended design
pin ⋅ do factors range from F = 0.40 for densely populated areas
t> (22.31)
2 ⋅ Sy with heavy traffic and multistory buildings (Class 4 loca-
tions) to F = 0.80 for deserts, wastelands, farmlands, and
The calculation of pipe wall thickness also includes addi- sparsely populated areas (Class 1 locations) [32]. ASME
tional safety factors that are prescribed by codes, standards, Standard B31.8 can be seen as somewhat more stringent or
and regulations and apply to the geographic location where conservative than Standard B31.4 because of the potential
the project is located. The basic equation for the determina- additional hazards that gas pipeline failures create com-
tion of wall thickness thus becomes pared with crude oil pipelines.
When ASME Standards B31.4 and B31.8 are compared
pin ⋅ do to ASME Standard B31.3, it is clear that the latter leads to
t= (22.32)
2Sy ⋅ F ⋅ E ⋅ T more conservative designs. This is because of the higher
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

levels of hazard associated with process piping found in

where: petroleum refineries and processing plants when compared
Pin = maximal operating pressure to which the pipe can be with crude oil and natural gas transmission systems. In
subjected (psia); the United States, most onshore facilities are designed in
F, E, and T = dimensionless safety factors; accordance to B31.4 and B31.8, depending on fluid type,
Sy = specified minimum yield strength of the pipe (psi) or whereas offshore facilities are mandated by regulation to
“SMYS,” which depends on pipe material and grade; follow ASME Standard B31.3 [31]. ASME Standard B31.3
F = a design derating factor; uses a modified form of Eq 22.30 for wall thickness calcula-
E = the weld joint derating factor; and tions, which include corrosion and thread allowances with
T = the temperature derating factor. more severe derating factors.
The most typical values used for each of these param- There are some other considerations that also influ-
eters are discussed below. The calculation in Eq 22.32 fixes ence the selection of recommended wall thickness and steel
the required wall thickness, hence the Schedule, of the pipe grade of the pipe. For example, for offshore applications,
required for the operation. Because Eq 22.32 requires the F derating design factors are typically made less than 0.80,
knowledge of outside diameter, few trials may be needed which makes offshore pipeline thicker and heavier than
with different plausible NPS and Schedule selections that pipelines used for inland applications. ASME B31.8 Chap-
are consistent with minimum internal diameter and thick- ter VIII covers the calculation of allowable pipe stresses
ness requirements. in these environments. Design factors of 0.72 and 0.50 are
The SMYS, or specified minimum yield strength of a recommended for offshore pipe wall thickness calculations,
pipe, refers to the specified minimum yield strength of a with the latter used for pipe sections such as risers that are
pipe manufactured according to the corresponding pipe subjected to the most stress during offshore operations.
material specification. As a result, the SMYS of a pipe When small diameter pipes are used offshore, they might
depends on its type of material specification (Table 22.1) not be able to sink in low-density saltwater environments.
and grade. For pipes manufactured according to API 5LX This can be compensated by deploying concrete weight
guidelines, the grade designation uses the letter X and the coatings or using even thicker wall pipe that can make the
first two digits of the specified minimum yield strength. pipe heavier [31,33]. In inland and offshore application,
The pipe specification API 5LX Grade X46 corresponds to piping should also be designed to support the bending
the grade having a specified minimum strength SMYS of stress induced by thermal expansion or contraction and the
46,000 psi, X60 implies a SMYS of 60,000 psi, X80, 80,000 movement of air or marine currents along the pipe path.
psi, etc. API 5L Grade A has one of the lowest SMYS values High-strength, high-grade pipes are typical in offshore
(30,000 psi) whereas Grade B has a SMYS of 35,000 psi. In applications for pipes to be able to support not only the
high-pressure applications, it is common to prefer higher- internal pressure readily taken into account in this section,
grade pipes (X52, X60, X65) because significantly less wall but also the external crushing force of the water column on
thickness would be required with associated lighter weights top of the line and associated bending stresses induced by
and lower cost [31]. undulations of the seabed and marine currents. For inland
For wall thickness calculations, ASME Standard B31.4 applications, if pipe thermal expansion or contraction can-
for onshore liquid transportation recommends F = 0.72 to not be fully absorbed by the pipe material, additional flex-
be used for all locations in Eq 22.30, does not implement ibility should be provided by deploying bends, expansion
temperature derating factors (T = 1), and recommends loops, and offsets [18].
weld joint derating factors (E) that depend on the welded
pipe class. For instance, E = 1 for seamless pipes and elec-
tric resistance welded (ERW) pipes; E = 0.80 for electric 22.10 Design Constraints
fusion arc and electric fusion welds; and E = 0.60 for fur- Pipe design must additionally consider the examination of
nace butt welded pipes. ASME Standard B31.8, used for the associated economics, resulting pressure drops, and
gas transportation, implements similar weld joint derat- prevailing flow velocities. Fluid flow velocities, for example,
ing factors (E) but recommends temperature-dependent must always be found within recommended minimal and
derating factors (T) that range from T = 0.867 for high maximal values, especially when flow of entrained par-
temperatures (approximately 450°F) to T = 1 for lower ticulate matter with the oil or gas or both phases is a real
temperatures up to 250°F [32]. The design factor F for gas possibility. Velocity constraints are usually an important
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562 Petroleum Refining and Natural Gas Processing

consideration because strict single-phase pipe operation or aximum of 90 ft/s for natural gas pipe transport but less
m
clean service can be a rare occurrence. Leading concerns than 25 ft/s if corrosion inhibitors are used [36]. He fur-
when constraining the velocity of a fluid inside of a pipe are ther indicates that for completely dry gas wells, no limit is
to control noise, vibration, erosion, corrosion, water ham- necessary to be placed on gas velocities [36], implying that
mer, and fluid carrying capacity. noise and vibration would not be of concern in gas well
Pipe design can be velocity constrained to avoid exces- applications.
sive noise production and pipe vibration during clean For two-phase systems, the API RP14E recommends
single-phase pipe service and multiphase flow. Noise con- the use of Eq 22.33, the erosional velocity equation, as the
trol is an important aspect of health and safety policies for maximal allowable velocity in carbon steel pipes,
industry workers and can become an important concern
for communities living along pipeline right of ways. In C
ve = (22.33)
addition, excessive vibration is a cause for material fatigue ρ
of the pipe material that could lead to catastrophic failure.
Flow-induced vibration and associated noise are indeed where:
studied as a coupled problem. Norton and Karczub explain ve = limiting erosional velocity (ft/s),
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

that noise and vibration in pipelines is a multistep process ρ = flowing mixture density (lb/ft3), and
that starts with the internal generation of random acoustic C = erosional empirical constant typically taking values
pressure fluctuations typical of turbulent (high velocity) anywhere in between 80 and 350 ft2.5/lb0.5-s.
flow, followed by the excitation (vibration) of the pipe wall The lower the selected value of C, the more constrained
in response to the fluctuating pressure signal closest to the the design and allowable velocities or flow rates. Although
wall, and finally the radiation of noise from the vibrating somewhat conservative values of C = 100 for continuous
pipe wall [34]. The presence of pipeline fittings (valves, service (and lower for sand-laden fluids) and C = 125 for
bends, and junctions) can significantly increase the inten- intermittent service were originally recommended by the
sity of the vibration and noise in the system because of API, less stringent values of C = 150–200 for continuous
the significantly increased pressure and flow disturbance service and C = 200–250 for intermittent service have also
they introduce. Sound waves generated by these localized been suggested for systems in which chemical corrosion is
disturbances at fittings are able to propagate undiminished actively controlled [31,35]. Brill and Mukherjee describe
through the pipe system [34]. Flow-induced noise and the topic of fluid-induced erosional velocity prediction as
vibration are thus controlled by reducing turbulence and rather controversial [11]. They point out some important
fluid disturbances; this is typically accomplished by placing limitations of Eq 22.33, such as its lack of compliance
maximal allowable fluid velocities in the system. Gas flows with experimental observations for sand-laden fluids, and
are more prone to noise and vibration problems because discuss alternative models available for the estimation of
of the higher associated Reynolds numbers and turbulence erosional velocity in petroleum applications. On the basis of
that characterize these systems. observations by Shirazi et al. [37], the authors point out that
Other problems associated with excessive fluid velocity although Eq 22.33 implies that erosional velocities decrease
are pipe wall erosion, ineffective corrosion inhibition, and when the density of the fluid increases, experience shows
water hammer. These are problems that, when not con- that sand in higher-density liquids actually causes less ero-
trolled, can significantly reduce the life span of the pipe. sion than sand in a lower density gas. The authors also
Pipe erosion can be caused by large fluid velocities and discuss the models of Shirazi et al. [37] and McLaury and
turbulence when particulate matter (e.g., liquid particles Shirazi [38], which account for the effect of pipe material
or sand) impinges the pipe wall, causing it to erode with and particle (sand) size, density, and sharpness and allow
time. The higher the fluid velocity, the more exposed the for the evaluation of various acceptable wall penetration
metal becomes to fluid-induced erosion. Excessive veloci- (erosion) rates. Despite these well-known weaknesses,
ties are also responsible for increased erosion at fittings Eq 22.33 remains popular because of its simplicity—the
and for the ineffective action of corrosion inhibitors. In very attribute that can actually make it potentially misleading
liquid systems, another concern with large fluid velocities and too constraining for realistic estimates. McLaury and
is the higher likelihood of water hammer problems. Water Shirazi [38] argue that the existence of such a wide range
hammer is the violent pressure surge that can be generated of recommended C values (C = 80–350 ft2.5/lb0.5-s—more
by sudden changes in fluid inertia (e.g., valve closings) and than a 4-fold difference between lower and upper predic-
that is especially problematic in nearly incompressible fluid tions without clear-cut selection criteria) is the very proof
systems. Water hammer can lead to pipe rupture because of of the inadequacy of the equation. The use of Eq 22.33 is so
its potentially destructive force and the presence of repeated widespread that it is even recommended for the calculation
stress that can weaken the pipe material to its point of fail- of maximal allowable velocities for single-phase flow—
ure. The first line of attack in the prevention of water ham- although it was originally proposed by API on the basis
mer damage is the control of liquid inertia through lower of two-phase flow experimental data. For example, Mohit-
design velocities. pour et al. [18] recommend constraining the gas velocity
In liquid-dominated systems, maximal velocities of in transmission gas lines to approximately 40–50 % of the
15 ft/s are suggested to minimize erosion and water ham- erosional value obtained from Eq 22.33 while using of C =
mer damage [31,35]. In gas lines, fluid velocities are typi- 100, which is equivalent to calculating a maximal allow-
cally recommended to be limited to 60–80 ft/s to prevent able velocity using C = 45 and can work out to be severely
excessive noise and vibration during clean service [31,35]. more constraining than applying the typical limit of 60–80
Kelkar quotes maximal recommended gas velocities of ft/s used for noise and vibration control. Kelkar [36] indi-
50 ft/s for production tubing of natural gas wells and a cates that Eq 22.33 is used in natural gas applications with
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Chapter 22 n Transportation of Crude Oil, Natural Gas, and Petroleum Products 563

values of C that vary between 100 and 150. Arnold and savings in initial capital expenditures (CAPEX) obtained by
Steward [35] indicate that Eq 22.33 is consistent with the selecting smaller and least costly pipe diameters. CAPEX
typically recommended maximum of 15 ft/s for liquid flow in pipeline projects does include pipe purchase cost and
when the equation is used with C = 125, which works out its installation, both of which can appreciably increase
to be the case for fluids with liquid specific gravities of as larger pipeline diameters are considered, plus the cost
approximately 1.11. of peripheral components such as compressors, pumps,
Pipeline flow can be velocity constrained at a lower valves, and monitoring equipment. OPEX in pipeline
bound as well. The main concern here is to ensure enough projects considers the annual capital outlays driven by
fluid carrying (“sweeping”) capacity and prevent the set- overall system maintenance and motive power generation.
tling, deposition, slugging, or surging of heavier phases Because CAPEX in pipeline project increases with pipeline
(liquids or solids) flowing with the fluid. A minimal diameter whereas OPEX tends to decrease with increasing
velocity of 3 ft/s is the typical recommendation for liquid- pipe diameters, an optimal or most economical pipe size
dominated pipe systems. In gas-dominated systems with can be defined when the sum of these two is minimized.
flowing liquids, minimal velocities should be at least 10–15 This is a constrained optimization problem because the
ft/s to ensure that liquids will flow [31,35]. Increasing fluid velocity restrictions discussed above must also be satisfied.
velocities to satisfy minimal velocity constraints for a given The optimization problem can also be construed in terms
pipe throughput entails considering smaller pipe sizes with of the maximization of the project’s present value based
increased pressure losses. Conversely, reducing fluid veloc- on discounted cash flows and estimated future revenues
ity to satisfy a maximal flow velocity constraint implies associated with the operation of the pipeline. The optimal
considering larger pipe diameters. The design equation diameter calculation would also yield the optimal pressure
presented as Eq 22.29 provides the minimal diameter that drop that should be pursued for the pipeline project under
satisfies the given transportation requirement. Any larger consideration. Economics drives pipeline design and thus
diameter adjusted not to surpass the maximal allowable informed pipeline design decisions should be made by
fluid velocity would still satisfy the transportation require- looking at the effect that they have over the lifetime span
ment, additionally yielding reduced wall friction losses. of the pipe operation. For example, the selection of higher
However, larger diameters could be problematic in terms grade line in exchange for smaller pipe thicknesses is also
of increased pipe costs and in two-phase operations, where an economic-driven design constraint.
the highly undesirable slug flow pattern becomes more
likely as pipe diameter increases. 22.11 Multiphase Flow Considerations
Another way of constraining pipe design and fluid Multiphase flow is very common in industrial processes.
velocities, or to determine if an ongoing pipeline opera- Many industrial processes rely on multiphase phenomena
tion is suboptimal or not, is through the control of for the transport of energy and mass or for material pro-
allowable/desirable pressure drop during pipe operations. cessing. Since the last century, the nuclear, chemical, and
For example, in the case of gas transportation, pressure petroleum industries have propelled an intense research
drop in pipes is typically constrained to reduce the load on activity in this area. Their effort has been aimed at the
compressors and compressor fuel costs. A maximal per- demystification of the mechanisms taking place during
missible pressure drop in gas lines is typically placed at this complex flow situation. Two-phase flow can be found
15 psi/mile, and gas velocity is adjusted so that the result- in various situations. Gas-liquid, liquid-liquid, solid-liquid,
ing pressure drop is found below this value. Mohitpour and solid-gas flows are the different two-phase flow permu-
et al. suggest that a pipe design that is based on resulting tations that can have the three more commonly encoun-
pressure drops between 3.5 and 5.85 psi/mile is optimal tered fluids in the petroleum industry (oil, natural gas, and
[17]. They argue that excessive pressure drops induce water). A solid phase can be found with the production
greater potential for operating problems and increased fluids from the reservoir itself (because of drilling activities
compressor load. Pressure drops below 3.5 psi/mile indi- or sand formation during production) or from the forma-
cate suboptimal use of available pipe capacity and facili- tion of complex solid structures because of the prevailing
ties. When designing a pipe based on a maximal pressure production conditions (hydrates in natural gas flow or
drop constraint, pipe equations can be solved for down- asphaltenes in oil flow).
stream pressure on the basis of a given flow capacity and Oil and natural gas transportation typically deals with
available upstream pressure by testing different commer- gas-liquid systems of flow. Because of the deformable
cially available finite pipe sizes until the target pressure nature of the simultaneously flowing fluids, flow of gas and
drop and velocity are attained. This protocol circumvents liquid in pipes represents a much more complex process
the iterations typically needed when trying to directly than single-phase flow. As a consequence of this deformable
solve for pipeline diameter. nature, gases and liquids may adopt a wide variety of spatial
A restriction in maximal allowable pressure drops flowing configurations known as flow patterns. Figure 22.5
in a system is essentially an economic constraint. When illustrates typical gas/liquid spatial distributions that can
there are no significant economic restrictions, such as in take place in horizontal flow in pipes. Pressure loss predic-
the case of freely available motive power from the fluid tions for each of these flow patterns are significantly more
source or reservoir, the smallest diameter pipe that satisfies complex than the single-phase flow predictions previously
the flow rate requirement is usually favored regardless of discussed. The prediction of the type of flow pattern taking
resulting pressure drop. However, this is hardly the case. place under the given operational conditions is typically a
Motive power provided by pumps and compressors can primary consideration because the mechanistic model and
become a significant operational expense over time. Ongo- empirical correlation that needs to be used to describe pres-
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

ing operating expenses (OPEX) can easily overcome any sure losses are dependent on it.
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564 Petroleum Refining and Natural Gas Processing

Stratified that most correlations were always best applicable for the
Smooth conditions for which they were derived from. One of the
Flow best well-known empirical correlations from the period is
Stratified
the one developed by Beggs and Brill for two-phase flow
Stratified
behavior prediction in inclined pipes [45]. Along with sev-
Wavy
Flow eral modifications applied to it, Beggs and Brill’s correla-
tion has become one of the most extensively used empirical
Elongated correlations in the petroleum industry. The correlation
Bubble considers horizontal, vertical, and inclined pipes, and the
Flow
Intermittent basic correlating parameter was the Froude number—the
Slug dimensionless number quantifying the relative influence
Flow of gravitational forces to inertial forces. Reliability of
empirical approaches is limited by the uncertainty of their
application to systems operating under different conditions
Annular
Flow
than those from which the correlations were originally
proposed. However, design of flow lines in multiphase
Annular
production facilities that is based on empirical correlations
Wavy was the norm until well into the 1980s and continues to be
Annular
popular. Brill and Mukherjee presents a complete review
Flow
of the tools available for pressure-gradient prediction of
Figure 22.5—Two-phase flow patterns in horizontal flow. multiphase flow in oil wells, which is composed of a diverse
Source: [39]. set of empirical correlations and more recent mechanistic
developments [11].
Flow pattern condition is a strong function of pipe The advent of the personal computer during the 1980s
inclination and relative amounts and velocities of the gas dramatically enhanced the capabilities of handling pro-
and liquid flowing in the pipe. One of the distinguished gressively more complex design situations, which Brill
features of modern multiphase prediction models is the and Arirachakaran called “the awakening years.” Much of
need for a reliable tool for the prediction of flow pattern the petroleum research on multiphase flow during these
transitions for a given set of operational conditions. Baker years and the subsequent modeling period was enriched
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

introduced what is considered the first useful attempt to by the progress already made by the nuclear industry [39].
creating a flow regime map for flow pattern determination Although the nuclear industry dealt with simpler fluids
[40]. One of the earliest attempts that introduced a fully (water and steam), it led the way toward more involved
phenomenological description of how transitions occur two-phase flow analysis in the petroleum industry. The
among the different flow patterns was the work developed work of Taitel and Dukler is considered one of the classical
by Taitel and Dukler [41], which focused on horizontal and papers in multiphase predictions that began to incorporate
near-horizontal pipes. This work led the way for the subse- more physical insight into the analysis in the petroleum
quent research in the area, and most of their transition cri- industry and spearheaded phenomenologically based mod-
teria are still in use in more recent two-phase flow models. eling efforts [41]. The modeling period, extending up to the
A few years after that initial work, Taitel et al. proposed the present day, refers to the growing tendency of introducing
model for the vertical and near-vertical case [42]. After- more physically based (mechanistic or phenomenological)
ward, Barnea extended the phenomenological approach approaches into multiphase flow calculations. The main
to the whole range of pipe inclinations [43]. These three goal remains at attempting to reduce the dependency on
works are commonly referenced among researchers in the empirical correlations during multiphase predictions. This
area and are the basis of numerous subsequent attempts for has been achieved through the implementation of two-fluid
prediction improvement. models, in which separate equations of mass and momen-
Brill and Arirachakaran presented an overview of tum conservation are written for each flowing phase.
how multiphase flow development was undertaken by Mechanistic modeling has since evolved as a compromise
the petroleum industry during the second half of the past between the use of empirical correlations and two-fluid
century [39]. They clearly divided this development into models. In mechanistic modeling, physical laws from the
three partially overlapping periods: the empirical period, two-fluid model approach are applied and empirical rela-
the awakening years, and the modeling period. During the tionships are used to achieve mathematical closure of the
empirical period, all of the efforts were focused on correlat- model. The studies of Xiao et al. [46], Ansari et al. [47],
ing data from laboratory and field facilities in an attempt and Kaya et al. [48] proposed steady-state comprehensive
to encompass the widest range of operational conditions mechanistic models for two-phase flow in horizontal pipes,
possible. One of the earliest attempts to empirically predict vertical wells, and deviated wells, respectively. Brill and
two-phase flow pressure drops is the well-known work of Mukherjee present a review of some of the steady-state
Lockhart and Martinelli for horizontal pipes [44]. This cor- mechanistic models available for the case of multiphase
relation was followed by an innumerable number of new flow in vertical wells [11]. Hasan and Kabir provide a com-
ones, which claimed to be progressively more applicable plete review of multiphase model developments for vertical,
for a wider range of operational conditions. Being the deviated, and horizontal wells [49]. More recently, Shoham
first quantitative approach to two-phase flow modeling, presented a comprehensive review of the mechanistic
Lockhart- Martinelli’s correlation became a classic against modeling of multiphase flow in pipelines, wellbores, and
which subsequent correlations were compared. The fact is inclined pipes [50].
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Chapter 22 n Transportation of Crude Oil, Natural Gas, and Petroleum Products 565

Expected pressure drops in gas-liquid pipes can be which can be re-expressed, on the assumption of same spe-
much higher than in single-phase pipes and much more cific resistances for all pipelines (when applicable), as
sensitive to pipe elevation and relative amounts and veloc-
ities of flowing phases. Significantly increased pressure Leq Lref Li
m
= = ∑i (22.34d)
losses can take place because of the interaction between dref deqm dim
the phases across their interface and the interaction of
each of the phases with the pipe wall. In various applica- The calculation of equivalent diameter for a system in
tions, increased pressure drops have been accounted for series entails the selection of a reference length (usually
by extending the application of single-phase models and total length), or, alternatively, the selection of a reference

--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---
assuming the flow of a single homogeneous pseudophase diameter (usually the most common in the system) for the
in the pipe. This can be shown to result in poor predic- calculation of an equivalent length. For the case of Hazen-
tions because it oversimplifies the multiphase flow prob- William equation for liquid flow (m = 4.87), equivalent pipe
lem. The use of single-phase equations for multiphase calculations are thus expressed as
flow applications forces the use of artificially inflated Li
values of single-phase friction factors. For example, in Leq = dref
4.87
⋅ ∑i (22.34e)
di4.87
natural gas applications, the use of low “efficiency fac-
tors” (Ef) is typically “recommended” when liquids are L0ref.20534
expected in the line. For such cases, efficiency factors of deq = 0.20534 (22.34f)
 Li 
 ∑ i 4.87 
Ef = 0.80 are not uncommon, and what this value does
is to artificially increase friction factor prediction of the  di 
gas equation by 54 %. The use of efficiency factors in the
order of Ef = 0.70 would more than double the friction For pipelines in parallel, pressure drop is the same in all
factor prediction of the equation. It is a better practice to pipe sections and total flow capacity equals the sum of all
implement special purpose multiphase flow correlations. flow rates transported for each line in the system. Thus,
Proper pipeline design must account for the effect of con- one writes
currently flowing phases on the performance of the line,
and for the purpose of more reliable predictions, readers ( qK )T = ∑ i ( qK )i (22.35a)
are referred to the mechanistic references and correla-
tions discussed above. or,

(Ceq ⋅ ∆p* n )T = ∑ i (CK ⋅ ∆p* n )i (22.35b)

22.12 Pipeline Networks and
Transportation Modeling Because all pipe sections share the same pressure drop, one
Most practical situations involve systems of pipelines readily derives the well-known relationship for calculation
that are interconnected forming a network. Typical net- of equivalent resistance and conductivity in an electrical
works can be made up of pipes in series, pipes in parallel, circuit in parallel:
branching pipes, and looped pipes. In complex network
analysis, it is not uncommon to reduce the complexity of 1 1
Ceq = ∑ i CKi → = ∑i n (22.35c)
the system as much as possible based on the concept of Reqn RKi
the equivalent pipe. On the basis of this and under cer-
On the assumption of same specific resistances for all
tain conditions, it usually proves convenient to replace
pipelines (when applicable), the above equation can be
a system of pipelines by single pieces of pipe of equiva-
expressed in terms of pipe dimensions as follows:
lent length or diameter. A single pipe is considered to be
equivalent to another system of pipes when it is capable of m⋅n
dref deqm⋅n dim⋅n
transporting the same fluid volume under the same pres- = = ∑i (22.35d)
sure drop requirement. L n
eq L n
ref Lni
For pipelines in series, flow rate is the same in all pipe
sections and total pressure drop equals the sum of all par- Therefore, and contingent on the definition of a reference
tial pressure drops per section; thus, dimension (length or diameter), pipe equivalent diameters
or lengths in circuits in parallel can be defined by apply-
ing Eq 22.35d. For example, for the case of the Weymouth
(∆p* )T = ∑ i (∆p* )i (22.34a) equation for gas flow (m = 16/3; n = 0.5), equivalent pipe
calculations are readily expressed as
or,
3/8
 d 8/ 3 
deq =  L0ref.5 ⋅ ∑ i i0.5  (22.35e)
Req ⋅ q1K/ n = ∑ i Ri ⋅ q1Ki/ n (22.34b)  Li 

16 / 3
Because flow rates are the same in all sections, we end up dref
Leq =
2 (22.35f)
with the well-known relationship for calculation of equiva-  di8/ 3 
lent resistance in an electrical circuit in series:  ∑ i 0.5 
 Li 
A well-known application of parallel pipe systems is
Req = ∑ i Ri (22.34c) the implementation of pipeline looping, which is the
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566 Petroleum Refining and Natural Gas Processing

most widely used way of increasing system capacity in N1

B1 N2 B2 N3
natural gas gathering system and transmission lines. It Supply Demand
consists of the use of a parallel, additional pipe of equal
or larger diameter and equal or shorter length that runs
parallel to the original existing line. Using the above B6 B7
B5
equations, it can be shown that the length of loop (x)
needed to increase system capacity from q K-orig to q K-new B4
is given by Supply N6
N4 B3 N5
1/ n
q  Supply
1 −  K − orig 
x q
 K − new 
= Figure 22.6—A pipeline network schematic.
1/ n (22.36)
L  d m⋅n 
1 −  m⋅n orig m⋅n 
 dorig + d  equations must match the number of unknowns in the
 new 

problem.
In the q-formulation, network equations are formulated
Equation 22.36 implies that, on the basis of predictions based on the principles of mass conservation or continuity
from Panhandle-B in a gas system, 40 % of an existing and energy conservation to solve for B unknowns (individ-
pipeline should be looped to increase the overall capacity of ual pipe flow rates). N equations of mass conservation can
the system by 20 % if a new parallel line of equal diameter be written at each nodal junction in the system. In nodal
is to be installed. mass conservation, the algebraic sum of flows entering and
Systems where the majority of the pipelines are inter- leaving the node must be equal to zero. In other words,
connected forming a network are the prevailing situation
in fluid transmission and distribution. Pipeline systems
that form a connected net or network are composed of
two basic elements: nodes and node connecting elements
∑ i
qkiin − ∑ i qkiout + S − D = 0 (22.37)

(NCEs). NCEs can include pipe legs, compressor or pump-

ing stations, valves, and pressure and flow regulators, written for each node and for all flows converging to it.
among other components. Nodes are the points where two Equation 22.37 is recognized as the first law of Kirch-
pipe legs or any other connecting elements intercept or hoff of circuits, in direct analogy to the analysis of flow of
where there is an injection or offtake of fluid. Modeling and electricity in electrical networks. S and D represent any
understanding the behavior of a network system is not a external supply or demand (sink/source) specified at the
matter of studying the performance of a single constituent node. For gas networks, this equation is actually a mass
component; but rather one must undertake a comprehen- conservation statement although it is written in terms of
sive study of the consequences of interconnectivity on the volumetric rates. For liquids, mass conservation and volu-
system. metric conservation go hand in hand because densities are
It is not uncommon for network systems to have at nearly constant. For gases, volumetric flow rates are always
least one closed pipe circuit or pipe loop. The presence of expressed at a common standard condition reference
pipe loops increases the reliability of delivery of the trans- (SCF), in which one unit of standardized volume contains
ported fluid because certain network nodes can be reached a fixed number of molecules (1 SCF = 379.4 lbmol). Equa-
simultaneously by more than one pipe. In network prob- tion 22.37 provides (N – 1) admissible equations because
lems, all physical features of the network are assumed to be only (N – 1) nodal equations are linearly independent. In
known and the analysis consists in determining resulting a network model, an overall mass balance must be always
flow through each pipe and associated nodal pressures. The in place when network problems are proposed because
steady-state assumption is typically embraced, although demand and supply nodes are balanced. Therefore, one
transient flow analysis is also possible at a much greater out of the N nodal conservation equations can be inferred
computational load. A steady-state network problem can be by subtracting the (N – 1) nodal equations from the overall
formulated in several ways. In general, it consists of a sys- demand and supply balance. As a consequence, LP addi-
tem made up of N nodes, B pipe branches or bridges (edges tional equations would be needed to exactly balance the
or arcs), and LP loops, as shown in Figure 22.6. Network number of unknowns B [B = (N – 1) + LP] and achieve
theory shows that these three quantities are mathematically mathematical closure of the q-formulation. These equa-
related through the expression B = (N – 1) + LP, where LP tions can be formulated by applying the second law of
represents the number of independent loops that can be Kirchhoff to every independent loop. In any loop in the sys-
defined in a network graph with N nodes and B branches. tem, the algebraic sum of all pressure drops must be equal
In Figure 22.6, B = 7, N = 6, and thus LP = 2. Network analy- to zero. This is true of any closed path in a network because
sis typically entails the calculation of flow capacity of each the value of pressure at any point of the network must be
pipeline segment (B-segments) and pressure at each pipe the same regardless of the path followed to reach the point.
--```,,,`,,,`,,`,,``,,``,,```,`,-`-`,,`,,`,`,,`---

junction (N-nodes) in a network. This can be accomplished The signs of the pressure drops are taken with respect to a
by either making pipe flows the primary unknowns of the consistent sense of rotation around the loop, and the loop
problem (i.e., the q-formulation, consisting of B unknowns) equation is written as
or by making nodal pressures the primary unknowns (i.e.,
the p-formulation, with N – 1 unknowns). In both cases,
to achieve mathematical closure, the number of available ∑ (∆p )
i
*
i = 0 (22.38)
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Chapter 22 n Transportation of Crude Oil, Natural Gas, and Petroleum Products 567

written for each loop and each pipe belonging to it. Loop these early approaches unnecessary, although they con-
equations must be rewritten in a q-formulation in terms of tinue to be an important reference and the basis of early
flow rates using the short form of the flow equation written computer software. Nowadays, the application of the mul-
in terms of pipe resistances: tivariate Newton-Raphson method is rather the norm for
the simultaneous solution of the large systems of nonlinear
∑ i
Ri ⋅ q1ki/ n = 0 (22.39) equations typically involved in network applications. The
most significant and widely known limitation of Newton-
Raphson methods is that it has the unfortunate tendency
Equation 22.37 provides (N + 1) equations and Eq 22.39 the of diverging hopelessly if it is not started sufficiently close
additional LP equations required to solve for B flow pipe to the actual solution (“local convergence”). As a result,
unknowns. Note that these equations are valid for liquid only globally convergent Newton-Raphson methods should
and gas flow networks and can be readily applied to any be implemented while solving complex network prob-
specialized flow equation provided that the proper values lems. In these methods, the quadratic local convergence
of RK, n, and m are applied. of Newton-Raphson is coupled with a globally convergent
In the p-formulation, network equations are formu- strategy that can better guarantee progress and conver-
lated based on the principles of nodal mass conservation gence toward the solution regardless of the starting point
(continuity) to solve for N – 1 unknowns (i.e., nodal pres- (see, for example, Press et al. [53]).
sures). One nodal pressure is assumed to be known in To circumvent Newton-Raphson convergence problems
the system and the rest are calculated as a function of it. and its potentially costly implementation, Ayala and Leong
Because only N – 1 equations are required, nodal mass recently proposed a robust linear-pressure pipe analog for
continuity equations are all that is required by this formula- the solution of highly nonlinear natural gas transportation
tion. However, Eq 22.37 must be written in terms of nodal networks [54]. The method consists in defining an alter-
pressures using the short form of the flow equation written nate, analog system of pipes that obey the simpler linear-
in terms of pipe resistances: pressure analog flow equation qgSC = CG′ ⋅ ( p1 − p2 ). When
gas pipe flows are written in terms of such linear analog,
∑C i Ki ⋅ (∆p* )ni + S − D = 0 (22.40a) nodal mass balance in Eq 22.40c collapses to very simple
algebraic equations in linear pressures shown in Eq 22.41:
In Eq 22.40, fluid flowing into the node is assumed positive
⋅ ( p1 − p2 )i + S − D = 0
and fluid leaving the node is given a negative sign. External ∑ C′i Gi (22.41)
supplies and demands (sink/sources) specified at the node
must also be considered. Again, these network equations which can be used to simultaneously solve for all nodal
are equally applicable to liquid and gas networks and can pressures in the network using any standard method of
be readily applied to any specialized flow equation when solution of linear algebraic equations. Ayala and Leong
the proper values of C, n, and m are applied. For liquids, demonstrate that all that is needed to create the linear-pressure
the equation is written in terms of pressure heads (see analog is to adjust actual pipe conductivities according to
Eq 22.4c): the following transformation [54]:

2
CG′ = CG ⋅ 1 + (22.42)
∑C i Li ⋅ ( hf )ni + S − D = 0 (22.40b) r −1

where:
For gases, the use of Eq 22.11 yields C′G = conductivity of the linear-pressure analog pipe,
CG = the actual pipe conductivity conforming to the general-
ized gas flow equation qgSC = CG ⋅ ( p12 − p22 )0.5 shown in Table
∑C Gi ⋅ ( p12 − p22 )ni + S − D = 0 (22.40c)
i

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