Sudan University of Science and Technology

College of Graduate Studies

Impact of American Petroleum Institute Standards Variation on Crude

Distillation Unit
(Khartoum Refinery Company Case Study)

‫أثـــر تغيـر معايير المعهد األمريكي للبترول على وحــدة تقطيــر البتــرول‬
)‫(دراســة حــالة شركة مصفــاة الخرطـــوم‬

A Thesis Submitted in Fulfillment for the Requirements of the Degree of Doctor of

Philosophy in Petroleum Refining

By

DHALLIA MAMOUN BESHIR MOHAMED

(B.Sc., M.Sc.)

Supervisors:
Dr. Ali A. Rabah
Dr. Sumaya A. Mohamed

January, 2015
 DECLARATION

I hereby declare that the thesis is based on my original work except for quotations and
citations which have been duly acknowledged. I also declare that it has not been
previously or concurrently submitted for any other degree at SUST or other institutions.

Signature: ______________________________________

Name : DHALLIA MAMOUN BESHIR MOHAMED

Date : ______________________________________

ii
 DEDICATION

To my father, Mamoun, whose encouragement was a great source

of inspiration to me;

to my aunt, Sommaya, for her support and love;

to my sister, Mayada, and my brothers, Hani and Beshir, who have

never ceased encouraging and supporting me whenever and where-

ever I faced difficulties during the entire span of this research

study;

to my husband, Mazin, for his love, patience and steadfast support;

and lastly but not least to my lovely kid, Ahmed, in whose

intelligent and bright eyes I see my own unfulfilled dreams coming

true in the neither too far nor too distant future.

iii
 ACKNOWLEDGEMENT

First and foremost, I would like to thank God the Almighty, for without his blessing, it
would have been impossible to achieve what had been done in this work.

Special acknowledgement goes to my supervisors, AP. Dr. Ali Abdelrahman Rabah and
Dr. Sumaya Abdel-Moneim Mohamed for their full and unwavering support to me in
every step of my project; bestowing me generously with all of their knowledge,
experience and critical thinking. I am really very thankful to them both.

Thanks and gratitude are rightly due to the members of the College of Petroleum
Engineering and Technology who generously contributed their ideas, expertise and
advice. Thanks are extended to the Sudan University of Science and Technology itself
which gave me the chance and supported me to complete my dream of doing a Ph.D.
program in refining engineering.

The author would like to express her gratefulness to her beloved family, father Mamoun,
aunt Sommaya, and her sister Mayada, and her brothers, Hani and Beshir, and her
husband Mazin and her child Ahmed, who have never ceased encouraging and supporting
her whenever she faced difficulties during the entire research study.

The author wishes to express her appreciation and gratitude to Khartoum Refinery
Company (KRC) members and Central of petroleum laboratory (CPL) members for their
assistance and support.

Thanks also go to my colleagues and friends, who supported and stood by me through the
good and bad times during the course of executing the various parts of the study.

iv
 ABSTRACT

This work aimed to study the effects of crude oil variation on the performance of a crude
distillation unit (CDU). CDUs are generally designed for specific type of crude oil.
However, the crude oil varies with time as a natural result of continuous reservoir
depletion. The CDU of Khartoum refinery was taken as a case study. Data covering the
period 2002 to 2012 was collected. The collected data include crude oil assay, feed and
products flow rate, and CDU design and operation data. The software HYSYS simulation
program was used to simulate refinery processes. The main parameters that are
considered include (1) design parameters of trays numbers and feed tray position and (2)
adaptation measures of reflux ratio. The CDU performance was measured by yield
percentage; the percentage of the product relative to maximum product that could be
obtained in accordance with crude assay. The HYSYS program was validated by an
example from the literature.

Regarding design parameters, the results showed that, when the crude oil becomes
heavier than the initial one (API decreases from 34.81 to 30.58) and under the same CDU
number of trays and feed position the performance decreases. Under these conditions it
yields less light product Naphtha and more of the heavy product residue. The Results
showed that the liquid volume percent decreased with number of trays for light products,
whereas the percentage increased for heavy product. The efficiency of producing naphtha
was found to be decreasing with increasing number of trays. And the efficiency of
minimizing the production of ATM Residue was found to be decreasing with increasing
number of tray. It is recommended to reduce number of trays to maximize the volume
percentage of naphtha, and to minimize the volume percentage of ATM Residue.

The results of the effect of feed tray position showed that the liquid volume percentage of
the light products increases with the feed tray position decreases, whereas the yield
decreases for heavy product. The adaptation measures of reflux ratio need to be decreased
to obtain high light product.

The study recommends the development of flexible CDU design by which the number of
trays and feed position can be changed. The current design does allow for such changes.
Flexible design however, calls for flexible pipe work and heat exchanger network as well.
v
 ‫المستخلص‬

‫استهدف هذا العمل دراسة آثر تغير النفط الخام علي أداء وحدة تقطير النفط الخام‪ .‬تم تصميم وحدات تقطير النفط‬

‫الخام بشكل عام لنوع معين من النفط‪ .‬بيد أن النفط الخام يختلف مع الوقت نتيجة طبيعية لنضوب الخزان المستمر‬

‫‪.‬واتخذت وحدة تقطير النفط الخام من مصفاة الخرطوم حالة للدراسة‪ .‬تم جمع البيانات التي تغطي الفترة من ‪2006‬‬

‫إلى عام ‪ .2012‬وتشمل البيانات التي تم جمعها فحص النفط الخام‪ ،‬ومعدل تدفق التغذية ومعدل تدفق المنتجات‪،‬‬

‫كما شملت ايضا بيانات تصميم وتشغيل وحدة تقطير النفط الخام‪ .‬تم استخدام برنامج محاكاة البرمجيات ‪HYSYS‬‬

‫لمحاكاة عمليات التكرير‪ .‬العوامل الرئيسية التي تم اعتبارها تشمل )‪ (1‬تصميم الصواني وموضع صينية التغذية و‬

‫)‪(2‬تدابير التكيف في نسبة الراجع‪ .‬يتم قياس أداء وحدة تقطير النفط الخام بنسبة مئوية العائد إلى النسبة المئوية من‬

‫الناتج نسبة إلى أقصى المنتجات التي يمكن الحصول عليها وفقا لفحص الخام‪ .‬يتم التحقق من صحة البرنامج‬

‫‪HYSYS‬بواسطة مثال من البحوث المنشورة‪.‬‬

‫بشأن معايير التصميم‪ ،‬أظهرت النتائج أنه عندما يصبح النفط الخام أثقل (‪ API‬يقل من‪ 34.81‬حتي‪ )30.58‬وتحت‬

‫نفس وحدة تقطير النفط الخام و رقم الصواني وموضع التغذية يقلل من األداء‪ .‬في ظل هذه الظروف انه يعطي أقل‬

‫منتج خفيف (النفثا) و المزيد من المنتج الثقيل (المتبقي)‪ .‬أظهرت النتائج أن نسبة حجم السائل انخفضت مع زيادة‬

‫عدد الصواني للمنتجات الخفيفة‪ ،‬في حين ارتفعت النسبة المئوية للمنتج الثقيل‪ .‬تم العثور على ان كفاءة إنتاج النافتا‬

‫تتناقص مع زيادة عدد من الصواني‪ .‬وعثر على ان كفاءة التقليل من إنتاج ‪ ATM‬المتبقي تتناقص مع زيادة عدد‬

‫الصواني‪ .‬ومن الموصى به التقليل من عدد من الصواني لذيادة نسبة حجم النفتا‪ ،‬وتقليل نسبة حجم المتبقي ‪.ATM‬‬

‫و اظهرت نتائج تأثير موضع صينية التغذية أن نسبة حجم السائل من المنتجات الخفيفة يزيد مع انخفاض في‬

‫موضع صينية التغذية‪ ،‬في حين ينخفض العائد للمنتج الثقيل ‪.‬بالنسبة لتدابيرالتكيف فانه ال بد من خفض نسبة الراجع‬

‫للحصول على منتج اعلى من المنتج الخفيف‪.‬‬

‫توصي الدراسة بتطوير تصميم وحدة مرنة لتقطير النفط الخام التي يمكن فيها تغيير عدد الصواني وموضع التغذية‪،‬‬

‫التصميم الحالي يسمح بمثل هذه التغييرات‪ .‬التصميم المرن مع ذلك يدعو للعمل بأبانابيب مرنة وشبكة مبادالت‬

‫ح اررية مرنة أيضا‪.‬‬

‫‪vi‬‬
 TABLE OF CONTENTS

DECLARATION ii

DEDICATION iii

ACKNOWLEDGMENT iv

ABSTRACT v

‫المستخلص‬ vi

TABLE OF CONTENT vii

LIST OF TABLES x

LIST OF FIGURES xi

NOMENCLATURE xiii

CHAPTER 1 .................................................................................................................. 1

INTRODUCTION ......................................................................................................... 1

1.1 BACKGROUND ........................................................................................................ 1

1.2 PROBLEM STATEMENT............................................................................................. 2
1.3 OBJECTIVE ............................................................................................................. 2
1.4 SCOPE OF THE STUDY .............................................................................................. 3
1.5 OUTLINE OF THE THESIS .......................................................................................... 3
CHAPTER 2 .................................................................................................................. 4

LITERATURE REVIEW ............................................................................................. 4

2.1 INTRODUCTION ....................................................................................................... 4

2.2 CRUDE OIL ............................................................................................................. 4
2.3 CRUDE OIL COMPOSITION ........................................................................................ 6
2.3.1 Paraffins (Alkanes) ......................................................................................... 7
2.3.2 Naphthenes (Cycloparaffins) ........................................................................... 7
2.3.3 Aromatics........................................................................................................ 8
2.3.4 Non-hydrocarbon Compounds ........................................................................ 8

vii
 2.4 CRUDE OIL CHARACTERIZATION METHODS ............................................................. 8
2.4.1 True boiling point ........................................................................................... 9
2.4.2 Gas chromatography..................................................................................... 12
2.5 CRUDE OIL REFINING............................................................................................ 13
2.5.1 Refining History ............................................................................................ 13
2.5.2 Examples of refineries ................................................................................... 17
2.5.3 Classifying Refineries by Configuration and Complexity ............................... 21
2.5.4 Classes of refining processes ......................................................................... 24
2.6 SIMULATION ......................................................................................................... 33
2.7 CONCLUSION ........................................................................................................ 35
CHAPTER 3 ................................................................................................................ 36

METHODOLOGY ...................................................................................................... 36

3.1 INTRODUCTION ..................................................................................................... 36

3.2 DATA COLLECTION ............................................................................................... 36
3.2.1 Production Data ........................................................................................... 36
3.2.2 Historical data .............................................................................................. 37
3.2.3 Design Data .................................................................................................. 37
3.3 SIMULATION PROGRAM ......................................................................................... 39
3.4 CASE STUDY (KHARTOUM REFINERY COMPANY) ................................................... 42
3.4.1 Crude Distillation Unit ................................................................................. 43
CHAPTER 4 ................................................................................................................ 49

RESULTS AND DISCUSSION .................................................................................. 49

4.1 INTRODUCTION ..................................................................................................... 49

4.2 CRUDE OIL CHARACTERIZATION ........................................................................... 49
4.2.1 Property of Crude oil .................................................................................... 49
4.2.1 Crude Oil Products Volume Percentage Yield ............................................... 51
4.3 SIMULATION OF REFINERY PROCESS FLOW DIAGRAM (PFD)................................... 52
4.3.1 Hysys Program Validation ............................................................................ 56
4.4 ASSUMPTION VALIDATION..................................................................................... 57
4.4.1 Influence of crude variation on product......................................................... 57
4.4.2 Comparison between HYSYS simulation and true boiling point results .......... 58
4.4.3 Comparison between HYSYS simulation and KRC results ............................. 59
4.5 RETROFIT MEASURES ........................................................................................... 61
viii
 4.5.1 Effect of Tray Numbers ................................................................................. 61
4.5.2 Effect of Feed Tray Position .......................................................................... 65
4.6 ADAPTATION MEASURES (EFFECT OF REFLUX RATIO) ........................................... 67
CHAPTER 5 ................................................................................................................ 69

CONCLUSION AND ECOMMENDATIONS ........................................................... 69

5.1 CONCLUSIONS ...................................................................................................... 69

5.2 RECOMMENDATIONS AND FUTURE WORK.............................................................. 72

REFERENCES ............................................................................................................ 73

APPENDICES............................................................................................................... 77

ix
 LIST OF TABLES

Table 2.1 Time Interval between Invention and Innovation for Nine Cracking Processes
from Enos 1962. ..................................................................................................... 16

Table 2.2 Refinery Classification Scheme...................................................................... 21

Table 2.3 Refinery Classes and Characteristic Yield Patterns......................................... 23

Table 2.4 Important Classes of Refining Processes ........................................................ 24

Table 2.5 Significant Features of Primary Conversion Processes ................................... 27

Table 2.6 Salient features of primary processes ............................................................. 29

Table 3.1 Pumparound Specifications ............................................................................ 38

Table 3. 2 Side Stripper Specifications .......................................................................... 38

Table 3.3 Side Stripper Specifications ........................................................................... 46

Table 3.4 Pumparound Specifications ............................................................................ 46

Table 3.5 Sample of Crude Oil General Tests for Year 2008.......................................... 47

Table 4.6 Properties of Nile Blend Crude ...................................................................... 50

Table 4.7: Summary of Volume Percentage Yield of the Products with Years ............... 51

Table 4.8 Comparison between Hysys Getting Started Module Results and this Research
Results ................................................................................................................... 56

Table 4.9 Summary of Volume Percentage Yield of the Products with API ................... 57

Table 4.10 The Expected Values of Volume Percentage from Hysys ............................. 63

x
 LIST OF FIGURES

Figure 2.1 Petroleum Products. ........................................................................................ 5

Figure 2.2 Classification of Crude Oil: Paraffins, Naphthenes, and Aromatics (Jones and

Pujado 2006) ............................................................................................ 7

Figure 2.3 TBP Product Components............................................................................. 11

Figure 2.4 Typical TBP Curve from Jones and Pujado 2006 .......................................... 11

Figure 2.5 Schematic flow chart of a very complexes refinery (Kraus, 2011). ................ 18

Figure 2.6 Schematic View of Crude Oil Distribution and Downstream Processing from

Pronic 2011 ............................................................................................ 20

Figure 3.1 Selection the Components 39

Figure 3.2 Peng-Robinson Equation of State Was Used ................................................. 40

Figure 3.3 The Assay Data Type (TBP) ......................................................................... 41

Figure 3. 4 The Cut Option (Auto Blend) ...................................................................... 41

Figure 3.5 Assay Definition Data................................................................................... 42

Figure 3. 6 KRC Products Balance Flow Chart (From KRC) ......................................... 44

Figure 3. 7 KRC Crude Distillation Unit (from This Work Results) ............................... 45

Figure 3. 8 Sample of TBP Curve Recovery on Weight and Volume Percent ................. 48

Figure 4.1: Summary of Yield Percentage for the Products 51

Figure 4.2 Process Flow Diagram of the Simulation Carried out in ASPEN HYSYS ..... 53

Figure 4.3 Distillation Column Sub Flow Sheet from Hysys .......................................... 55

xi
Figure 4.4 Volume Percentage Yield of the Products with API ...................................... 58

Figure 4.5 Volume Percentage Yield of Hysys Simulation and TBP Versus API for

Naphtha .................................................................................................. 58

Figure 4.6 Volume Percentage Yield of Hysys Simulation and TBP Versus API for

Residue .................................................................................................. 59

Figure 4.7 Weight Percentage Yield of Hysys Simulation and KRC Versus API for

Naphtha .................................................................................................. 60

Figure 4.8 Weight Percentage Yield of Hysys Simulation and KRC Versus API for

Residue .................................................................................................. 60

Figure 4.9 Effect of Varying Number of Trays on Naphtha ............................................ 61

Figure 4.10 Effect of Varying Number of Trays on ATM Residue ................................. 62

Figure 4. 11 Effect of Varying Number of Trays on Naphtha via Different API Values . 63

Figure 4. 12 Effect of Varying Number of Trays on ATM Residue via different API

values ..................................................................................................... 64

Figure 4.13 Effect of Varying Feed Tray Position on Naphtha ....................................... 66

Figure 4.14 Effect of Varying Feed Tray Position on ATM Residue .............................. 66

Figure 4.15 Effect of Varying Reflux Ratio on the Naphtha ........................................... 67

Figure 4.16 Effect of Varying Reflux Ratio on the ATM Residue .................................. 67

xii
 NOMENCLATURE

AGO Atmospheric Gas Oil.

ATM Atmospheric

ASTM American Standard Test Methods

API American Petroleum Institute.

CDU Crude Distillation Unit.

C/H Carbon/Hydrocarbon.

FCC Fluid Catalytic Cracking

kbpd Kilo Barrel Per Day

LPG Liquefied Petroleum Gases

TBP True boiling point.

USA United States of America.

VRC Vacuum Reduced Crude

xiii
 Chapter 1

INTRODUCTION

1.1 Background

Oil refining is one of the most complex chemical industries, which involves many
different aspects and complicated processes with various possible connections. The
objective in refinery operations is to generate as much profit as possible by converting
crude oils into valuable products such as gasoline, jet fuel, diesel, and so on (Zhang et al.,
2000). In recent years the requirements for large quantities of liquid hydrocarbons,
particularly gasoline and diesel fuels have increased and will continue to escalate, which
will necessarily cause steady rise in production volume of the refining industry. The
International Energy Agency in its World Energy Outlook 2008 is predicting the increase
in yearly oil use to be 1.3% until 2020 and 1.0% from 2020 to 2030 (Muzic et al., 2010).

There are several technologies available in order to separate a mixture, including

extraction, crystallization, semi-permeable membranes, distillation etc. Amongst these
technologies, the distillation process has been found to be having substantial advantages
over other processes. As a rule, it is the most cost-effective process, so it may be used for
mixtures with very diverse properties (Page et al., 1985). Distillation is the oldest and the
most universal process of chemical technology and other branches of industry
incorporating separation of mixtures. In petroleum refineries, there are many distillation
columns that are presently working satisfactorily well. There are also several others that
are not working as well, and at least a few that function very poorly, or not at all. Failure
to obtain the specified and required performance is due, in many cases, to faulty or
inadequate control system design. Troubleshooting of columns that are already in
operation is frequently necessary, but practical considerations usually limit corrective
Chapter 1: Introduction 2

measures to relatively minor items. Proper original design is by far the best way to
guarantee satisfactory operation and control (Page et al., 1985).

Simulation is presently a mature well tested technology and it is widely used for a variety
of purposes, including design, control, test, optimization, and integration of process plants
(Denn; Tracy et al., 2004). Simulations can save a lot of time and money. More-over,
they are a lot cheaper and much faster than running series of experiments. In this study
simulation using HYSYS program will be used in order to study the effect of
characteristic variation on the design of crude oil distillation column.

1.2 Problem statement

The properties of crude oil vary during the years, this may affect the products
specifications, which will make it difficult to achieve the quality performance specified
for the distillation column. Proper original design is by far the best way to guarantee
satisfactory operation and control. Although simulation is presently a mature well tested
technology which is widely used for design of process plants, there is no documented
scientific literature on studying the influence of crude variation on product, as well as the
design of flexible distillation column.

1.3 Objective

The primary goal of this research is to study the impact of feed characteristic variation on
the distillation performance, as well as the design of flexible distillation column. Hence
the objectives of this study are:

 To characterize crude oil feed.

 To simulate a refinery distillation column.
 To study the impact of feed characteristic variation on the products.
 To investigate the influence of varying number of trays, feed tray position, and
reflux ratio on products.
Chapter 1: Introduction 3

1.4 Scope of the study

The goal of this research is to study the impact of feed characteristic variation on the
products, as well as the design of flexible distillation column. To achieve this goal, the
following four tasks were carried out:

 Data for crude oil characterization was collected for year 2002 to 2012;

 Hysys simulation program was used to simulate refinery processes; the simulation
results will be verified;

 The impact of feed characteristic variation from year 2002 to 2011 on the products
was investigated;

 Year 2012 was taken as a reference year in order to investigate the influence of
varying number of trays, varying feed tray position, and varying reflux ratio on
product.

1.5 Outline of the Thesis

The rest of this thesis is organized as follow: Chapter 2 discusses background information
required to comprehend this thesis. The chapter introduces an overview of the crude oil
composition, crude oil characterization methods and crude oil refining, as well as the
simulation usage in oil refining. Chapter 3, methodology, includes the production,
historical and design data results. It also describes the procedure of the simulation
program and the case study. Chapter 4 displays and discusses results. The final chapter
presents conclusions along with recommendations for further research.
 Chapter 2

LITERATURE REVIEW

2.1 Introduction

The following is a review of literature on previous research and studies that have been
conducted on crude oil, and its characterization techniques as well as crude oil refining
industry and simulation usage in oil refining. This review of previous work on the subject
is vitally important as the first step in starting this project and in assisting with the setting
up of the simulation program.

2.2 Crude Oil

Crude oil is a term used to describe hydrocarbon rich mixtures that accumulated over
millions of years and are usually found underground (Klerk 2008). Oil's primary
importance lies in the fact that it is a very versatile and powerful source of energy.
Petroleum's importance to humankind took a giant leap in the late 1800's when it replaced
coal as the primary fuel for the machines of the industrial revolution. In today's
industrialized society, petroleum means power. It provides the mechanical power to run
machines and industries and also the political power that comes from being able to shut
down the machines and industries of those who depend on you for their oil supply. Oil is
a non-renewable source of energy. What this means is that our natural sources of oil are
finite; there will come a time when we have used them up (Fagan 1991).

Although oil is primarily an energy source, it is also used as a raw material in

manufacturing more than a thousand other products including; plastics, paints, fertilizers,
Chapter 2: Literature Review 5

detergents, cosmetics, insecticides, and even food supplements. Figure 2.1shows some of
the more familiar ones. At the refinery, crude oil is separated into fractions through
distillation. Some of these fractions, through simple treating, are converted to final
petroleum products at the refinery. Other refined products require further processing at
chemical plants and factories showing up as final consumer products.

Refinery

Gasoline - Jet Fuel - Diesel - and Others

Petrochemical Plant

Asphalt - Candles - Detergents - Medicines – Plastics - Polish – Roofing - Others

Figure 2.1 Petroleum Products.

Sudan produces two main blends of crude oil: Nile, a light, sweet and waxy blend; and
Dar, a heavy and sour blend that is more difficult to refine. As such, Nile blend is sold at
much higher prices than Dar, according to an April 2008 report funded by the European
Union. Sudan also produces the highly acidic Fula blend, from the fields of the same
name located in northwestern Sudan, which is processed mostly for Sudan’s domestic use
(http://www.oilwest.biz/dar-blend-crude-oil/ 2014). The Nile Blend is sourced from
Blocks 2 (Heglig and Bamboo fields) and 4 (Diffra and Neem fields) in Sudan and Blocks
1 (Unity field) and 5A (Mala and Thar Jath fields) in Southern Sudan. Nile blend gives
the least content of sulfur in comparison with oils from the world
(http://www.eia.gov/countries/cab.cfm?fips=su 2014).
Chapter 2: Literature Review 6

2.3 Crude oil composition

Crude oil is a mixture of hundreds of hydrocarbon compounds ranging in size from the
smallest, methane, with only one carbon atom, to large compounds containing 300 and
more carbon atoms. Not all compounds contained in crude oil are hydrocarbons; it may
also include compounds of sulfur, nitrogen, oxygen, and metals. By far the most
important and the most common of these impurities is sulfur. The hydrocarbons present in
crude oil are classified into three general types (Figure 2.2): paraffins, naphthenes, and
aromatics (Matar and Hatch 2000; Jones and Pujad 2006).

Although all crude oils contain the composition described above, rarely there are two
crude oils with the same characteristics. This is so because every crude oil from whatever
geographical source contains different quantities of the various compounds that make up
its composition (Jones and Pujado 2006).
Chapter 2: Literature Review 7

PARAFFINS

Normal butane (C4H10) Iso-butane (C4H10)

AROMATICS NAPHTHEN
ES

Benzene (C6H6) Cyclohexane (C6H12)

Figure 2.2 Classification of Crude Oil: Paraffins, Naphthenes, and Aromatics (Jones
and Pujado 2006)

2.3.1 Paraffins (Alkanes)

Alkanes are saturated hydrocarbons having the general formula C nH2n+2. The simplest
alkane, methane (CH4), is the principal constituent of natural gas. Methane, ethane,
propane, and butane are gaseous hydrocarbons at ambient temperatures and atmospheric
pressure. They are usually found associated with crude oils in a dissolved state. The
number of possible isomers increases as the molecular weight of the hydrocarbon
increases (Jones and Pujado 2006; Matar and Hatch 2000).

2.3.2 Naphthenes (Cycloparaffins)

Naphthenes are saturated cyclic hydrocarbons. There are many types of naphthenes
present in crude oil. The lower members of naphthenes are cyclopentane, cyclohexane,
Chapter 2: Literature Review 8

and their mono-substituted compounds. They are normally present in the light and the
heavy naphtha fractions. Heavier petroleum fractions such as kerosene and gas oil may
contain two or more cyclohexane rings fused through two vicinal carbons (Jones and
Pujado 2006; Matar and Hatch 2000).

2.3.3 Aromatics

Aromatic hydrocarbons contain a benzene ring which is unsaturated but very stable and
frequently behaves as a saturated compound. The simplest mononuclear aromatic
compound is benzene (C6H6). Toluene (C7H8) and xylene (C8H10) are also mononuclear
aromatic compounds found in variable amounts in crude oils (Jones and Pujado 2006;
Matar and Hatch 2000).

2.3.4 Non-hydrocarbon Compounds

The most important non-hydrocarbon compounds are the organic sulfur, nitrogen, and
oxygen compounds. Small quantities of metallic compounds are also found in all crude
oil material. The presence of these impurities is harmful and may cause problems to
certain catalytic processes. Fuels having high sulfur and nitrogen levels cause pollution
problems in addition to the corrosive nature of their oxidization products (Jones and
Pujado 2006; Matar and Hatch 2000).

2.4 Crude Oil Characterization Methods

Characterization of complex mixtures is a common tool especially in oil processing

industry. To establish the simulation both the operating variables (input specifications)
and the definition of the mixture have to be specified first (Leelavanichkul, Deo et al.
2004; Eckert and Vanek 2005).

Crude oil is a mixture of literally hundreds of hydrocarbon compounds ranging in size

from the smallest, methane, with only one carbon atom, to large compounds containing
300 and more carbon atoms. Each crude oil type has unique molecular, chemical
Chapter 2: Literature Review 9

characteristics. No crude oil type is identical and there are crucial differences in crude oil
quality (Encyclopedia 2013).

In any simulation problem, all feed streams must be completely defined before the
calculation can begin. For a stream to be completely defined there must be enough
information present to calculate the enthalpy. A crude oil assay is a compilation of
laboratory and pilot plant data that define the properties of the specific crude oil

The crude oil assay is essentially the chemical evaluation of crude oil feed stocks by
petroleum testing laboratories. At a minimum the assay should contain a distillation curve
for the crude and a specific gravity curve. The assay can be an inspection assay or
comprehensive assay. Testing can include crude oil characterization of whole crude oils
and the various boiling range fractions produced from physical or simulated distillation
by various procedures. Most assays however contain data on pour point (flowing criteria),
sulfur content, viscosity, and many other properties.

The results of crude oil assay testing provide extensive detailed hydrocarbon analysis data
for refiners, oil traders and producers. Information obtained from the petroleum assay is
used for detailed refinery engineering and client marketing purposes. Feedstock assay
data are an important tool in the refining process (encyclopedia, 2013).

2.4.1 True boiling point

The True boiling point distillation (TBP) is the single most important information for any
crude oil for modeling of a crude distillation column. The TBP distillation tends to
separate the individual mixture components relatively sharply in order of boiling point
and is a good approximation of the separation that may be expected in the plant (Figure
2.3 and Figure 2.4). There are many types of standard distillation tests that determine the
boiling point distribution of petroleum fuels, the inter-conversion between which is well
documented.

Some of the more common standard test methods for distillation of petroleum products
include: ASTM D86-96, which is performed under atmospheric pressure and is used for
Chapter 2: Literature Review 10

determining the boiling point distribution of light petroleum fractions, such as naphtha,
kerosene, diesel, and light gas oil; micro-distillation; molecular distillation; fractional
distillation (typically using a spinning band still); ASTM D5236 distillation (typically
using a pot still); D1160 (for heavy petroleum fractions); ASTM D3710 (simulated
distillation, which is also known as the GC SimDist method, and uses gas
chromatography to determine the true boiling point, or TBP, of gasoline); ASTM D2887
(GC SimDist to determine the TBP of petroleum fraction other than gasoline); ASTM
D2892 (also known as 15/5 distillation, which produces simulated TBP of petroleum
fuels using a distillation column with 15 theoretical plates and a reflux ratio of 5); ASTM
D5236 Distillation (also known as the vacuum pot still method, and is used for heavy
hydrocarbon mixtures); ASTM D5307 (SimDist for determining TBP of crude oil);
ASTM D6352-98; and Hemple analysis for the distillation of a large volume of fuel
samples providing further detailed analysis of the produced distilled cuts. ASTM D86-96
and D1160 may be combined together for determining the boiling point distribution of
wide boiling range materials, such as crude oils. ASTM Distillation tests for gasoline,
naphtha (A naphtha is a volatile petroleum fraction, usually boiling in the gasoline range),
and kerosene (D86); natural gasoline (D216); and gas oil (D158) involve much the same
procedure (Chasib, 2011).

In general the true boiling point analysis according to ASTM D-2892 standard is the
single reliable tool for characterization of crude oil and petroleum mixtures in terms of
their boiling point distribution (Nedelchev et al., 2011).
Chapter 2: Literature Review 11

TBP Distillation

Naphtha Kerosene Gasoil ATM Residue

C5-140 oC 140-240 oC 240-370 oC 370+ oC

Vac Gasoil SR
370-540 oC 540-600 oC

Figure 2.3 TBP Product Components

Figure 2.4 Typical TBP Curve from Jones and Pujado 2006
Chapter 2: Literature Review 12

2.4.2 Gas chromatography

Chromatography is the collective term for a set of laboratory techniques for the
separation of mixtures. Gas chromatography is broadly used for characterizing crude oil
(hydrocarbons), and numerous advances in this method have originated in petroleum
industry laboratories (Gautam et al., 1998, Barman et al., 2000). Moreover, its use has
markedly increased in the last few years with the progress in instrumentation and the
relatively low cost of the equipment (Durand, 2000).

Gas chromatography (GC), also sometimes known as gas-liquid chromatography,

(GLC), is a separation technique in which the mobile phase is a gas. Gas
chromatography is always carried out in a column, which is typically packed or
capillary. Gas chromatography is based on a partition equilibrium of analyte between a
solid stationary phase (often a liquid silicone-based material) and a mobile gas (most
often helium). The stationary phase is adhered to the inside of a small-diameter glass
tube (a capillary column) or a solid matrix inside a larger metal tube (a packed column)
(Wikipedia, 2013).

In 2000 Barman et al have provided a broad overview of major chromatographic

techniques that have been applied to the characterization of petroleum and related
products. They have discussed the scope, applicability, and versatility of individual
techniques such as gas chromatography, liquid chromatography, supercritical fluid
chromatography, thin-layer chromatography, and size-exclusion chromatography. They
have found that analytical approaches vary widely depending on the chromatographic
technique, instrumentation, minimum detection limit, and sample type. Several
techniques such as open-column liquid chromatography, medium pressure liquid
chromatography, high-performance liquid chromatography (HPLC), and supercritical
fluid extraction provided separation of compound classes for subsequent characterization
by higher solution chromatography, spectroscopy, hyphenated or multi technique
chromatographic approaches which have also been described (Barman et al., 2000).
Chapter 2: Literature Review 13

2.5 Crude Oil Refining

Oil refining is one of the most complex chemical industries, which involves many
different aspects and complicated processes with various possible connections. The
purpose of a refinery operations is to generate as much profit as possible by converting
crude oils into valuable products which meet market demands such as gasoline, jet fuel,
diesel, and so on (James et al., 2001; Zhang et al., 2000; Gary and Awqand Handwerk
2001; Klerk 2008; Wauquier 2000).

Compared to the starting of production of crude oil era during the years span of the
1850’s, the market for crude oil derived products changed dramatically today. In recent
years the requirements for large quantities of liquid hydrocarbons, particularly gasoline
and diesel fuels, have increased and will continue to escalate, which will necessarily
cause a steady rise in the production volume of the refining industry. The International
Energy Agency in its World Energy Outlook 2008 is predicting the increase in yearly oil
use to be 1.3% until 2020 and 1.0% from 2020 to 2030 (Muzic et al., 2010).

Today, crude oil is refined all over the world. The largest oil refinery is the Paraguana
Refining Complex in Venezuela, which can process 940,000 barrels of oil each day. In
fact, most of the oil industry’s largest refineries are in Asia and South America.
Nevertheless, the practice of refining oil was created in the United States, where it
continues to be an important part of the nation’s economy.

2.5.1 Refining History

Samuel M. Kier, a native of southwestern Pennsylvania state in the United States of

America (U.S.A.), was the first person to refine crude oil. In the mid 1840s, he became
aware of crude oil through his salt business. Kier first used the flammable oil produced by
his salt wells to light his salt works at night. The burning crude produced an awful smell
and a great deal of smoke. Nevertheless, Kier was able to light his business without
paying for an expensive illuminant like whale oil. In partnership with John T. Kirkpatrick,
Kier created the first U.S.A. petroleum refinery in Pittsburgh, Pennsylvania. He started
with a small one or two-barrel still, but by 1854, he had a larger five-barrel still in
operation. When Edwin L. Drake struck oil near Titusville, Pennsylvania in 1859, the
market became flooded with oil, and Pittsburgh saw seven new oil refineries come into
Chapter 2: Literature Review 14

operation. By the end of the 1860s, there were 58 refineries operating in Pittsburgh alone.
Samuel M. Kier spent a great deal of his life trying to make crude oil useful and valuable
and along the way he helped give birth to the U.S.A refining industry
(http://www.oil150.com/files/refining-crude-oil-history,-process-and-products.pdf).

In the early days of the oil industry, the methods for refining oil were very different from
the method in use today. People like Samuel M. Kier used horizontal cylindrical stills that
only held 5 to 6 barrels of oil at a time. Using the stills, refiners were able to raise the
temperature of the oil very slowly. As the temperature rose, they removed the distillates
like gasoline for which they had no use, procuring only the lamp oil or kerosene. Over
time, oil’s other distillates became useful and the refining process evolved. Once it enters
the modern refinery, crude oil goes through a process called fractional distillation. This
process separates the different components of crude oil so that they can be further refined.
Fractional distillation begins when the crude oil, which is a mixture of different
hydrocarbons, is put into a high-pressure steam boiler. This is a tank that makes the oil
boil and turn to vapor, much like boiling water turns into water vapor. The crude oil is
heated to temperatures up to 1112° Fahrenheit (http://www.oil150.com/files/refining-
crude-oil-history,-process-and-products.pdf).

After the oil becomes vapor, it enters the bottom of the distillation column through a pipe.
The distillation column is a tall tank that contains many plates or trays. The vapor rises in
the column, cooling as it rises. The specific vapors cool at their respective boiling points
and condense on the plates or trays in the column. Much like water condensation on the
outside of a cold glass, the vapors turn into liquid fractions as they condense. The liquid
fractions flow through pipes and are collected in separate tanks. The fractions include
gases, naphtha, gasoline, kerosene, diesel fuel, lubricating oils, heavy oils, and other
materials. From here, the liquid fractions are transported to other areas of the refinery for
further processing (http://www.oil150.com/files/refining-crude-oil-history,-process-and-
products.pdf).

Modern refinery is much affected by the new environmental aspects of the industry, as
well as the use of heavier crude oils and crude oils with higher sulfur and metal content.
And these criteria affect the processing options and the processing equipment required in
a modern refinery (Garry 2001). The refining operations concerned with blending
Chapter 2: Literature Review 15

products in an optimum manner with the twin objectives of meeting product demand and
maximizing refinery profit (Parkash, 2003).

The composition of the total mixture, in terms of elementary composition, does not vary a
great deal, but small differences in composition can greatly affect the physical properties
and the processing required for producing salable products. Sulfur contents and densities
increment will affect quality of processed crude oils. The greater densities will mean
more of the crude oil will boil above 566 0C (1050 0F). Historically this high-boiling
material or residua has been used as heavy fuel oil but the demand for these heavy fuel
oils has been decreasing because of stricter environmental requirements. This will require
refineries to process the entire barrel of crude rather than just the material boiling below
1050 0F (566 0C). Sulfur restrictions on fuels (coke and heavy fuel oils) will affect
bottom-of-the-barrel processing as well. These factors will require extensive refinery
additions and modernization and the shift in market requirements among gasolines and
reformulated fuels for transportation will challenge catalyst suppliers and refinery
engineers to develop innovative solutions to these problems (Enos, 1962).

The first commercially successful process to crack heavy hydrocarbons into motor
gasoline components was introduced in 1913. Since then there have been eight more
process innovations, comprising three waves, one in the early 1920's, another in 1936,
and the final one in the 1940's. Each successive wave has yielded improved processes,
which have generally displaced those from an earlier wave. The processes utilized first
heat and pressure and then catalysts to promote the cracking reaction. They were initially
non continuous and subsequently continuous in operation (Enos, 1962).
Chapter 2: Literature Review 16

Table 2.1 Time Interval between Invention and Innovation for Nine Cracking
Processes from Enos 1962.
Invention Innovation Interval
Between
Nature of Date Description Name of Date of First
Invention
Invention Made process Commercial
and
Operation
Innovation
Distilling 1889 Bath thermal Burton 1913 24
Hydrocarbon cracking
s with heat
and pressure
Distilling gas oil 1910 3
with heat and
pressure
Continuous 1909 Continuous Holmes- 1920 11
cracking thermal Manley
cracking
Continuous 1909 Continuous Dubbs 1922 13
cracking thermal
cracking
“Clean 1919
circulation”

Continuous 1909 Continuous Tube and 1922 13

cracking thermal Tank
cracking
Continuous 1915 Continuous Cross 1920 5
cracking of thermal
gas oil cracking
Catalytic 1927 Semi- Houdry 1936 9
cracking of continuous
gas oil and catalytic
catalyst cracking
regeneration
Fludized bed of 1929 Continuous Fluid 1942 13
catalyst catalytic
cracking
Moving bed of 1936 Continuous T.C.C. 1944 8
catalyst; catalytic
regeneration cracking
Gas lift for 1937 Continuous T.C.C. and 1950 13
catalyst catalytic Houdriflow
pellets cracking
Chapter 2: Literature Review 17

2.5.2 Examples of refineries

Each refinery has its own unique processing scheme which is determined by the process
equipment available, crude oil characteristics, operating costs, and product demand. The
optimum flow pattern for any refinery is dictated by economic considerations and no two
refineries are identical in their operations (Pronic, 2011).

Refineries produce dozens of refined products (ranging from the very light, such as LPG,
to the very heavy, such as residual fuel oil). They do so not only because of market
demand for the various products, but also because the properties of crude oil and the
capabilities of refining facilities impose constraints on the volumes of any one product
that a refinery can produce. Refineries can, and do, change the operations of their
refineries to respond to the continual changes in crude oil and product markets, but only
within physical limits defined by the performance characteristics of their refineries and
the properties of the crude oils they process (Optimization, 2011).
Chapter 2: Literature Review 18

Figure 2.5 Schematic flow chart of a very complexes refinery (Kraus, 2011).
Chapter 2: Literature Review 19

Figure 2.5 is a simplified flow chart of a notional (typical) modern refinery producing a
full range of high-quality fuels and other products. It is intended only to suggest the
extent and complexity of a refinery’s capital stock, the number of process units in a
typical refinery, and the number of co-products that a refinery produces. An appreciation
of this complexity is essential to a basic understanding of the refining industry
(Optimization, 2011).

Figure 2.5 shows the processing sequence in a modern refinery of high complexity,
indicating major process flows between operations. The crude oil is heated in a furnace
and charged to an atmospheric distillation tower, where it is separated into butanes and
lighter wet gas, unstabilized light naphtha, heavy naphtha, kerosene, atmospheric gas oil,
and topped (reduced) crude (ARC). The topped crude is sent to the vacuum distillation
tower and separated into vacuum gas oil stream and vacuum reduced crude bottoms
residua, reside, or VRC. The reduced crude bottoms (VRC) from the vacuum tower is
then thermally cracked in a delayed coker to produce wet gas, coker gasoline, coker gas
oil, and coke. Without a coker, this heavy resid would be sold for heavy fuel oil or (if the
crude oil is suitable) asphalt. Historically, these heavy bottoms have sold for about 70
percent of the price of crude oil (Optimization, 2011).

Figure 2.6 is a simpler schematic representation of a petroleum refinery. This exhibit

illustrates, in schematic form, the separation of crude oil into specific boiling range
(carbon number) fractions in the crude distillation process, shows standard industry
names for these crude fractions, and indicates the subsequent refinery processing of these
streams to produce a standard slate of finished refined products (Optimization, 2011).
Chapter 2: Literature Review 20

Figure 2.6 Schematic View of Crude Oil Distribution and Downstream Processing from Pronic 2011
Chapter 2: Literature Review 21

2.5.3 Classifying Refineries by Configuration and Complexity

Each refinery’s configuration and operating characteristics are unique. They are
determined primarily by the refinery’s location, vintage, preferred crude oil slate, market
requirements for refined products, and quality specifications (e.g., sulfur content) for
refined products. Although no two refineries have identical configurations, they can be
classified into groups of comparable refineries, defined by refinery complexity
(Optimization, 2011).

Broadly speaking, all refineries belong to one of four classes, defined by process
configuration (the size of the various units, their salient technical characteristics, and the
flow patterns that connect these units) and refinery complexity (it has two meanings; one
is the non-technical meaning: intricate, complicated, consisting of many connected parts;
the other is a numerical score that denotes, for a given refinery), as shown in Table 2.2
(Optimization, 2011).

Table 2.2 Refinery Classification Scheme

Configuration Complexity

Ranking Range

Topping Low <2

Hydroskimming Moderate 2–6

Conversion High 6 – 12

Deep conversion Very high > 12

Topping refineries have only crude distillation and basic support operations. They have
no capability to alter the natural yield pattern of the crude oils that they process; they
simply separate crude oil into light gas and refinery fuel, naphtha (gasoline boiling
range), distillates (kerosene, jet fuel, diesel and heating oils), and residual or heavy fuel
Chapter 2: Literature Review 22

oil. A portion of the naphtha material may be suitable for very low octane gasoline in
some cases. Topping refineries have no facilities for controlling product sulfur levels.

Hydroskimming refineries include not only crude distillation and support services but
also catalytic reforming, various hydrotreating units, and product blending. These
processes enable (1) upgrading naphtha to gasoline and (2) controlling the sulfur content
of refined products. Catalytic reforming upgrades straight run naphtha to meet gasoline
octane specification and produces by-product hydrogen for the hydrotreating units.
Hydrotreating units remove sulfur from the light products (including gasoline and diesel
fuel) to meet product specifications and/or to allow for processing higher-sulfur crudes.
Hydroskimming refineries, commonplace in regions with low gasoline demand, have no
capability to alter the natural yield patterns of the crudes they process.

Conversion (or cracking) refineries include not only all of the processes present in
hydroskimming refineries but also, and most importantly, catalytic cracking and/or
hydrocracking. These two conversion processes transform heavy crude oil fractions
(primarily gas oils), which have high natural yields in most crude oils, into light refinery
streams that go to gasoline, jet fuel, diesel fuel, and petrochemical feedstocks. Conversion
refineries have the capability to improve the natural yield patterns of the crudes they
process as needed to meet market demands for light products, but they still (unavoidably)
produce some heavy, low-value products, such as residual fuel and asphalt.

Deep Conversion (or coking) refineries are, as the name implies, a special class of
conversion refineries. They include not only catalytic cracking and/or hydrocracking to
convert gas oil fractions, but also coking. Coking units “destroy” the heaviest and least
valuable crude oil fraction (residual oil) by converting it into lighter streams that serve as
additional feed to other conversion processes (e.g., catalytic cracking) and to upgrading
processes (e.g., catalytic reforming) that produce the more valuable light products. Deep
conversion refineries with sufficient coking capacity destroy essentially all of the residual
oil in their crude slates, converting them into light products.

Table 2.3 summarizes the salient features of the different refinery classes and indicates
their characteristic product yield patterns at constant crude oil quality. Actual refinery
yield patterns can vary significantly from these patterns, depending on the specific crude
Chapter 2: Literature Review 23

slate and the specific performance characteristics of the refinery’s process units
(Optimization, 2011).

Table 2.3 Refinery Classes and Characteristic Yield Patterns

Product yeld
Refinery Characteristic profile (vol%)
Comments
category processes Diesel
Gasoline
& Jet
 Product sulfur levels
same as crude fraction
sulfur levels.
 Product yields and
Topping  Crude distillation. 31 30
quality determined
solely by crude
properties.
 Gasoline has low octane.
 Product sulfur levels
controllable by
hydrotreating.
 Crude distillation.
 Some capability to
Hydroskimming  Reforming. 28 33
improve product yields
 Hydrotreating. and quality.
 Gasoline octane
improved by reforming.
 Crude distillation.
 FCC and/or  Product sulfur levels
hydrocracking. controllable by
hydrotreating.
Conversion  Reforming. 44 32
 Substantial capability for
 Alkylation & yield and quality
other upgrading. improvement.
 Hydrotreating.
 Crude distillation.
 Product sulfur levels
 Cocking.
controllable by
 FCC and/or
hydrotreating.
Deep hydrocracking.
47 42  Maximum capability for
conversion  Reforming.
quality improvement.
 Alkylation &
 Essentially all residual
other upgrading.
oil “destroyed”.
 Hydrotreating.
Chapter 2: Literature Review 24

2.5.4 Classes of refining processes

Table 2.4 shows important classes of refining processes including crude distillation,
conversion, upgrading, treating, separation, blending, and utilities (Optimization, 2011).

Table 2.4 Important Classes of Refining Processes

Class Function Examples
 Separate crude oil into boiling range  Atmospheric
Crude
fractions for further processing. distillation.
distillation
 Vacuum distillation.
 Break down (“crack”) heavy crude  Fluid catalytic
fractions into lighter refinery steams for cracking (FCC).
Conversion
further processing or blending.
 Hydrocracking .
(“Cracking”)

 Rearrange molecular structures to  Catalytic reforming.

improve the properties (e.g., octane) and  Alkylation,
Upgrading
value of gasoline and diesel components. Isomerization.
 Remove hetro-atom impurities (e.g.,  FCC hydrotreating.
sulfur) from refinery streams and blend  Reformer feed
stocks. hydrotreating.
Treating  Remove aromatics compounds from  Gasoline and distillate
refinery streams. hydrotreating.
 Benzene saturation.
 Separate, by physical or chemical means,  Fractionation
constituents of refinery streams for (numerous).
Separation
quality control or for further processing.  Aromatics extraction.
 Combine blendstocks to proceed finished  Gasoline blending.
products that meet product specifications  Jet and diesel
Blending
and environmental standards. blending.
 Refinery fuel, power, and steam supply;  Power generation.
sulfur recovery; oil movements; crude
 Sulfur recovery.
Utilities and product storage; emissions control;
etc.
Chapter 2: Literature Review 25

These categories are discussed briefly below.

2.5.4.1 Crude Distillation

Crude oil distillation is the front end of every refinery, regardless of size or overall
configuration. It has a unique function that affects all the refining processes downstream
of it. Crude distillation separates raw crude oil feed (usually a mixture of crude oils) into
a number of intermediate refinery streams (known as “crude fractions” or “cuts”),
characterized by their boiling ranges (a measure of their volatility, or propensity to
evaporate). According to optimization 2011 (Optimization, 2011) each fraction leaving
the crude distillation unit

 is defined by a unique boiling point range (e.g., 180–2580o F, 250–350o F, etc.) and;

 is made up of hundreds or thousands of distinct hydrocarbon compounds, all of which

have boiling points within the cut range.

These fractions include (in order of increasing boiling range) light gases, naphthas,
distillates, gas oils and residual oil (as shown in Figure 2.5). Each goes to a different
refinery process for further processing.

The naphthas are gasoline boiling range materials; they are usually are sent to upgrading
units (for octane improvement, sulfur control, etc.) and then to gasoline blending. The
distillates, including kerosene, usually undergo further treatment and then are blended to
jet fuel, diesel and home heating oil. The gas oils go to conversion units, where they are
broken down into lighter (gasoline, distillate) streams. Finally, the residual oil (or
bottoms) is routed to other conversion units or blended to heavy industrial fuel and/or
asphalt. The bottoms have relatively little economic value – indeed lower value than the
crude oil from which they come. Most modern refineries convert, or upgrade, the low-
value heavy ends into more valuable light products (gasoline, jet fuel, diesel fuel, etc.).

Because all crude oil charged to the refinery goes through crude distillation, refinery
capacity is typically expressed in terms of crude oil distillation throughput capacity.
Chapter 2: Literature Review 26

2.5.4.2 Conversion (Cracking) Processes

Conversion processes carry out chemical reactions that fracture (“crack”) large, high-
boiling hydrocarbon molecules (of low economic value) into smaller, lighter molecules
suitable, after further processing, for blending to gasoline, jet fuel, diesel fuel,
petrochemical feedstocks, and other high-value light products. Conversion units form the
essential core of modern refining operations because they:

 enable the refinery to achieve high yields of transportation fuels and other valuable
light products,

 provide operating flexibility for maintaining light product output in the face of normal
fluctuations in crude oil quality, and

 permit the economic use of heavy, sour crude oils.

The conversion processes of primary interest are fluid catalytic cracking (FCC),
hydrocracking, and coking. Visbreaking, another conversion process, is similar in
function to coking. Visbreaking is used primarily in Europe.

Table 2.5 provides a brief comparison of some significant properties of these three
processes (Optimization, 2011).

The Carbon/Hydrogen (C/H) ratio Adjustment item in Table 2.5 requires some
explanation. As noted previously, the heavier (more dense) the crude oil, the higher its
C/H ratio. Similarly, within any given crude oil, the heavier the boiling range fraction, the
higher its C/H ratio. The same phenomenon applies to refined products: the heavier the
product, the higher its C/H ratio. Consequently, refining operations must, in the
aggregate, reduce the C/H ratio of the crude oil and intermediate streams that they
process. Much (but not all) of this burden falls on the conversion processes.

Broadly speaking, reducing the C/H ratio can be accomplished via one of two ways:
either by rejecting excess carbon (in the form of petroleum coke) or by adding hydrogen.
It is worth mentioning that FCC and coking follow the former path; hydrocracking
follows the latter path.
Chapter 2: Literature Review 27

Table 2.5 Significant Features of Primary Conversion Processes

Features FCC Hydro-cracking Coking

Primary feeds

SR Distillate

SR Gasoil Oil

SR Residual Oil

Coker Gasoil

FCC Slurry Oil

Process Type

Catalytic

Thermal

C/H Ratio Adjustment

Carbon Rejection

Hydrogen addition

Primary functions

Increase light product yield

Produce additional FCC feed

Remove hetro-atoms (including sulfur)

Sulfur Content of Cracked Products Moderate to High < 100 ppm Very
High
Chapter 2: Literature Review 28

2.5.4.3 Upgrading Processes

Upgrading processes carry out chemical reactions that combine or re-structure molecules
in low-value streams to produce higher-value streams, primarily high-octane, low sulfur
gasoline blendstock. The upgrading processes of primary interest all employ catalysts,
involve small hydrocarbon molecules, and are applied to gasoline production.

The most important of the many upgrading processes are catalytic reforming, alkylation,
isomerization, polymerization, and etherification. Table 2.6 provides a brief summary of
some of the salient properties of upgrading processes.
Chapter 2: Literature Review 29

Table 2.6 Salient features of primary processes

Reforming Alkylation Isomerization Polymerization Etherification

Primary feeds

SR Naphtha
(med. and heavy.)

SR Naphtha
(light)

Natural gasoline

Iso-butane

C3 Olefin

C4 Olefins

Methanol/Ethanol

Primary products

Gasoline Reformate Alkylate Isomerate Poly Gasoline MTBE

Blendstock

Other Hydrogen

Primary functions

Improve refinery
yield gasoline

Add octane to the

gasoline pool

Control gasoline
pool octane

Produce refinery
hydrogen
Chapter 2: Literature Review 30

2.5.4.4 Treating (Hydrotreating) Processes

Treating processes carry out chemical reactions that remove hetero-atoms (e.g., sulfur,
nitrogen, heavy metals) and/or certain specific compounds from crude oil fractions and
refinery streams, for various purposes. The most important purposes are:

 meeting refined product specifications (e.g.; sulfur in gasoline and diesel fuel,
benzene in gasoline, etc.), and

 protecting the catalysts in many refining processes from deactivation (“poisoning”)

resulting from prolonged contact with hetero-atoms.

By far the most widely-used of the various treating technologies is catalytic

hydrogenation, or hydrotreating.

Hydrotreaters remove hetero-atoms by reacting the refinery streams containing the

hetero-atom(s) with hydrogen in the presence of a catalyst. The hydrogen combines with
the hetero-atom(s) to form non-hydrocarbon molecules that are easily separated from
refinery streams. Hydrotreating has many forms and degrees of severity; as a result, it
goes by many names in the refining industry and in the literature. Hydrotreating focused
on sulfur removal is often referred to as hydro-desulfurization; hydrotreating focused on
nitrogen removal is called hydro-denitrification; and so on. Hydrotreating conducted at
high severity (i.e., high temperature, pressure, and hydrogen concentration) often involves
some incidental hydrocracking as well. Deep hydrotreating of this kind is called hydro-
refining. Hydrotreating conducted at low severity is used to modify certain characteristics
of specialty refined products (e.g., various lubricating oil properties) to meet
specifications. Mild hydrotreating is often called hydro-finishing.

2.5.4.5 Separation Processes

Virtually all refinery streams are mixtures of hydrocarbon compounds. Separation

processes use differences in the physical and chemical properties of these compounds to
separate one refinery stream into two or more new ones.

Distillation, or fractionation, the most common separation process, uses differences in

boiling point temperatures to effect separations into relatively lighter (lower boiling) and
relatively heavier (higher boiling) mixtures. Distillation employs well-established
technology and is doubtless the most widely used refining process; distillation units
(fractionators) are ubiquitous in refineries.
Chapter 2: Literature Review 31

Extraction, another common separation process, uses differences in the relative

solubilities of different compounds in a liquid solvent to remove specific compounds
from hydrocarbon mixtures. The most common refining application of extraction is
aromatics extraction, which selectively removes certain aromatics compounds from the
highly aromatic reformate stream produced in catalytic reforming. The extracted
aromatics (benzene, toluene, and xylene) are primary petrochemical feed stocks.

2.5.4.6 Utilities and Support Operations

Refineries encompass many additional process units of varying complexity and purpose.
Some produce specialty products (waxes, lubricants, asphalt, etc.); others control
emissions to air and water; and still others provide support to the mainline processes
discussed above.

The primary support facilities include

♦ Hydrogen production and recovery,

♦ Sulfur recovery (from desulfurization processes)

♦ Light gas handling and separation,

♦ Wastewater treatment

♦ Oil movement and storage

♦ Electricity and steam generation

Hydrocrackers and hydrotreaters require substantial inputs of hydrogen. As noted above,

some of the refinery hydrogen requirement is met by by-product hydrogen produced in
the reformer. The rest of the hydrogen requirement is met by on-purpose hydrogen
production units in the refinery or by purchases of hydrogen from near-by merchant
hydrogen plants. These units produce hydrogen from natural gas. Because on-purpose
hydrogen is expensive, regardless of its source, most refineries also have facilities for
recovering and recycling the spent hydrogen in hydrocracking and hydrotreating effluent
streams.

Refinery processes use fuel and steam to heat and/or boil process streams and to provide
the energy needed to drive chemical reactions, and they use electricity for running pumps
and compressors. Some refineries purchase fuel (natural gas), electricity, and/or steam;
Chapter 2: Literature Review 32

others generate some or all of their utilities on-site. On-site generation involves traditional
steam boilers and power generation facilities, or co-generation. Co-generation is the
integrated production of electricity and steam, at very high thermal efficiency, using
either purchased natural gas or refinery-produced light gas as fuel.

2.5.4.7 Product Blending

Product blending is the operation at the back end of every refinery, regardless of its size
or overall configuration. This operation consists of blending refinery streams in various
proportions to produce finished refined products whose properties meet all applicable
industry and government standards, at a minimum cost. The various standards pertain to
physical properties (e.g., density, volatility, boiling range); chemical properties (e.g.,
sulfur content, aromatics content, etc.), and performance characteristics (e.g., octane
number, smoke point).

Production of each finished product requires multi-component blending because:

 refineries produce no single blend component in sufficient volume to meet demand

for any of the primary blended products such as gasoline, jet fuel, and diesel fuel,

 many blend components have properties that satisfy some but not all of the relevant
standards for the refined product into which they must be blended, and

 cost minimization dictates that refined products be blended to meet, rather than
exceed, specifications to the extent possible. Typically, gasoline is a mixture of ≈ 6–
10 blendstocks; diesel fuel is a mixture of ≈ 4–6 blendstocks.

Gasoline blending is the most complex and highly automated blending operation. In
modern refineries, automated systems meter and mix blendstocks and additives. On-line
analyzers (supplemented by laboratory analyses of blend samples) continuously monitor
blend properties. Computer control and mathematical models establish blend recipes that
produce the required product volumes and meet all blend specifications, at minimum
production cost. Blending of other products usually involves less automation and
mathematical analysis.
Chapter 2: Literature Review 33

2.6 Simulation

The availability of computers beginning in about 1950 permitted two advances to take
place; the ability to work with non-linear differential equations (usually ordinary), and the
ability to study larger systems. Analog computers were used at first but later were mostly
replaced by digital computers (Page et al., 1985).

Simulation is presently a mature well tested technology and it is widely used for a variety
of purposes, including design, control, test, optimization, and integration of process plants
(Denn, 2004, Casavant and Cote, 2004). Simulations can save a lot of time and money.
More-over, they are a lot cheaper and much faster than running series of experiments.
To establish the simulation both the operating variables (input specifications) and the
definition of the mixture have to be specified first (Eckert et al.; Leelavanichkul et al.,
2004). Simulations according to Denn, Tracy et al., 2004 can have a wide range of
purposes which may include the following (Denn, Tracy et al., 2004):
 Predicting off-design performance of existing systems to identify and mitigate
possible problems.
 Optimizing the efficiency of a system during the design process to decrease
energy costs.
 Determining how a modification in one part of an existing system will affect the
rest of the system

Chryssolouris, Papakostas et al., 2005 have proposed a simulation-based approach to the

refinery operation, which addressed primarily the scheduling of a refinery importing
various types of crude oil (Chryssolouris et al., 2005). Pan, Li et al., 2009 have presented
a new approach for crude oil scheduling, which can avoid composition discrepancy
without using iterative algorithm and find better solution effectively. They have used a
new mixed integer non-linear programming (MINLP) for crude oil scheduling firstly, and
then proposed some heuristic rules collected from expert experience to linearize bilinear
terms and prefix some binary variables in the MINLP model (Pan et al., 2009).
Robertson, Palazoglu et al., 2011 suggested a multi-level simulation approach for the
crude oil loading/unloading scheduling problem. They have used the nonlinear simulation
model for the process units to find optimized refining costs and revenue for a blend of
Chapter 2: Literature Review 34

two crudes. Results showed that this integrated approach can lead to a decrease of
production and logistics costs or increased profit, provide a more intelligent crude
schedule, and identify production level scheduling decisions which have a tradeoff benefit
with the operational mode of the refinery (Robertson et al., 2011).

ASPEN HYSYS is a strong and versatile tool for the simulation studies, modeling and
performance monitoring for oil and gas production, gas processing, petroleum refining,
and air separation industries. It helps to check the feasibility of a process, to study and
investigate the effect of various operating parameters on various reactions (Agrawal
2012).

HYSYS offers a high degree of flexibility because there are multiple ways to accomplish
specific tasks. This flexibility combined with a consistent and logical approach to how
these capabilities are delivered makes HYSYS an extremely adaptable process simulation
tool ( AspenHYSYSUserGuide 2005).

HYSYS has strong thermodynamic foundation. The inherent flexibility contributed

through its design, combined with the unparalleled accuracy and robustness provided by
its property package calculations leads to the representation of a more realistic model.
HYSYS also contains a powerful regression package that may be used in conjunction
with its tabular capabilities. Experimental pure component data, which HYSYS provides
for over 1,000 components, can be used as input to the regression package
(AspenHYSYSSimulationBasis 2005).

As explained in the HYSYS User Guide and HYSYS Simulation Basis guide, HYSYS
has been uniquely created with respect to the program architecture, interface design,
engineering capabilities, and interactive operation. The integrated steady state and
dynamic modeling capabilities, where the same model can be evaluated from either
perspective with full sharing of process information, represent a significant advancement
in the engineering software industry. The various components that comprise HYSYS
provide an extremely powerful approach to steady state process modeling. By using a
‘degrees of freedom’ approach, calculations in HYSYS are performed automatically.
HYSYS performs calculations as soon as unit operations and property packages have
enough required information (AspenHYSYSOperationsGuide 2005).
Chapter 2: Literature Review 35

2.7 Conclusion

Crude oil is a term used to describe hydrocarbon rich mixtures that accumulated over
millions of years and are usually found underground. This crude can be converted to other
more useful products. The objective in refinery operations is to generate as much profit as
possible by converting crude oils into valuable products such as gasoline, jet fuel, diesel,
and so on. The market need for these products is ever increasing all the time, which will
necessarily cause a steady rise in production volume of the refining industry. Distillation
has been found to have substantial advantages in separating mixtures. As a rule,
distillation is the most cost-effective process, so it may be used for mixtures with very
diverse properties such as crude oil. In petroleum refineries, there are many distillation
columns that are presently working satisfactorily well. There are also several others that
are not working so well, and at least a few that function very poorly, or not at all. Failure
in obtaining the quality performance specified for the distillation column is most
commonly due to faulty or inadequate control system design. Simulation is presently a
mature and well tested technology and it is widely used for a variety of purposes,
including design, control, test, optimization, and integration of process plants.

To date, past studies generally concentrated on using simulation in crude oil scheduling.
Furthermore, it is distinctly clear from the findings of this literature review that there is no
work in the area of using simulation to study the influence of crude characteristic
variation on product, as well as the design of flexible distillation column. Therefore, this
project aims to study the impact of feed characteristic variation on the design of
distillation column.
 Chapter 3

METHODOLOGY

3.1 Introduction

Generally in the field of scientific research it is important to describe in detail the

methods which are followed up and used. In this work and in order to achieve the
objectives of this thesis, the methods can be divided into three main categories as follows;
(1) Data collection, (2) Simulation program and (3) Case study (Khartoum refinery
Company).

3.2 Data Collection

Data of Nile Blend crude was collected from Khartoum Refinery Company and Central
Petroleum Laboratory. The data consist of:

1. Production data
2. Historical data
3. Design data

3.2.1 Production Data

The weight percentage yield and the amount of crude oil products which were produced
from the atmospheric distillation column were collected from Khartoum Refinery
Company. The products consisted of Naphtha, Kerosene, Diesel and Atmospheric
Residue.
Chapter 3: Methodology 37

3.2.2 Historical data

Crude assay reports for Nile blend were collected for the years 2002, 2004, 2006, 2007,
2008, 2009, 2010, 2011 and 2012. The crude oil was characterized using the true boiling
point (TBP) analysis. The assay report contains crude oil general tests (density, API,
viscosity, pour point, water content, salt content, acid number, sulfur content, and
asphaltenes results for crude); TBP distillation data; and the volume as well as weight
percentage yield of crude distillation column products (Naphtha, Kerosene, Diesel, and
Residue). It also contains general test results for products.

3.2.3 Design Data

A refinery process flow diagram was built using the following design data from HYSYS
getting started module in order to built up the simulation (Technology, 2004).

3.2.3.1 Simple pre-heat train (Heat Exchanger, a Desalter, two simple Heaters and a
Pre-Flash Separator)

In any simulation problem, all feed streams must be completely defined before the
calculation can begin. For a stream to be completely defined there must be enough
information present to calculate the enthalpy. For mixtures, this requires the composition
plus any two of the temperature, pressure, or vapor fraction. For pure components that are
saturated or two phases, it is necessary to define the composition and the vapor fraction
plus either the temperature or the pressure.

First the crude was at 15°C, 1000 kPa and 6e+005 kg/h. This crude was then fed to a
heater, heat exchanger, a desalter, two simple heaters and a pre-flash separator, to
complete a simple pre-heat. In the first heater the pressure drop was 50kPa and the
temperature of the crude was raised to 65°C. In the heat exchanger the pressure drops for
the tube and shell sides was 35 kPa and 5 kPa respectively. Typically, after this
preheating the first unit that the crude oil will pass through is the desalter. After the
desalter the crude was heated 175°C in a simple heater with a pressure drop of 375 kPa.
Finally after this heating the crude will enter a preflash separator. The pre-flash tower is
responsible for separating the crude vapors and liquid entering into the crude column as a
bottom feed. This is carried out to reduce the duty of the furnace to devise an economical
Chapter 3: Methodology 38

process (Benali 2012). The bottom product of the pre-flash tower was fed to a furnace
operating at a pressure drop of 250kPa with the crude being heated to 400˚C.

3.2.3.2 Atmospheric Crude Column

Atmospheric crude columns are one of the most important pieces of equipment in the
petroleum refining industry. Typically located after the desalter and the crude furnace, the
atmospheric tower serves to distil the crude oil into several different cuts. These include
naphtha, kerosene, light diesel, heavy diesel and AGO.

The column consists of 29 stages with a partial condenser, three side strippers and three
pumparounds. The heated crude was sent to the tray 28. Side strippers comprising 3
stages were utilized for diesel and atmospheric gas oil (AGO) (Table 3.2). Fractionation
was increased by reducing the partial pressures with the aid of steam and a reboiler for
Kerosene (Table 3.2). The pressure drop at the top of the CDU was 60 kPa with a top and
bottom stage pressure of 14kPa and 230kPa, respectively. Internal reflux was ensured by
the installation of three pumparounds as in Table 3.1. There was a bottom steam entering
at tray 29at a rate of 3400kg/hr, 194.6˚C and 1380kPa.

Table 3.1 Pumparound Specifications

Location
Pump around (PA) between Duty (kW) Flow (kBPD)
trays
AGO 22 and 21 -3.7e+007 30
Diesel 17 and16 3.7e+007 30
Kerosene 9 and 8 -4.5e+007 50

Table 3. 2 Side Stripper Specifications

Location
Side stripper (SS) between Stripped by Flow/Duty
trays

AGO 22 and 21 Steam 30 m3/h

Diesel 17 and16 Steam 130 m3/h

Kerosene 9 and 8 Reboiler 1.105 e+007 kJ/h

Chapter 3: Methodology 39

3.3 Simulation program

The Aspen Hysys (V8.0 (27.0.0.38)) simulation program was used for the simulation
studies and the investigation of the effect of various operating parameters, because it
offers a high degree of flexibility to accomplish a specific task. This flexibility combined
with a consistent and logical approach to show these capabilities are delivered makes
HYSYS an extremely adaptable process simulation tool (Technology, 2005b).

The first thing which was done in order to build up the simulation case was selecting the
components (Figure 3.1).

Figure 3.1 Selection the Components

HYSYS has strong thermodynamic foundation. The inherent flexibility contributed

through its design, combined with the unparalleled accuracy and robustness provided by
its property package calculations lead to the representation of a more realistic model. The
equation of State models was chosen as a fluid property package, because it has proven to
be very reliable in predicting the properties of most hydrocarbon based fluids over a wide
range of operating conditions. The Peng-Robinson Equation of State was used among the
equation of states models (Figure 3.2) because it has a high accuracy for a variety of
Chapter 3: Methodology 40

systems over a wide range of conditions. It also rigorously solves most single-phase, two-
phase, and three-phase systems with a high degree of efficiency and reliability
(Technology, 2005a).

Figure 3.2 Selection of Peng-Robinson Equation of State

Then TBP was chosen as the assay data type Figure 3.3, auto blend option was used for
cut option (Figure 3. 4). After that the bulk properties data, light end composition,
distillation curve data, molecular weight, density and viscosity curves data were inserted
Figure 3.5.
Chapter 3: Methodology 41

Figure 3.3 The Assay Data Type (TBP)

Figure 3. 4 The Cut Option Selection (Auto Blend)

Chapter 3: Methodology 42

Figure 3.5 Assay Definition Data

After the assay was completely defined, the equipment design data for each equipment
from section 3.2.3.1 was inserted in the simulation. First the Simple Heater 1 was
inserted then Heat Exchanger, then Desalter and Simple Heater 2. Lastly a Preflash
Column and a Furnace were inserted as well as the Distillation Column.

3.4 Case Study (Khartoum refinery Company)

Khartoum refinery Company (KRC) is the largest refinery in Sudan (Figure 3.6); it is
located just north of Khartoum and has a crude distillation capacity of 100,000 bbl/d. It
initially came online in 2000 with a capacity of 50,000 bbl/d to process the Nile Blend
(http://www.eia.gov/countries /cab.cfm?fips=su, 1/4/2014).
Chapter 3: Methodology 43

3.4.1 Crude Distillation Unit

The crude distillation unit in KRC consists of 52 stages with a partial condenser, three
side strippers and three pumparounds (Figure 3.7). The heated crude is sent to in the tray
4. Side strippers comprising 3 stages have been utilized for diesel and atmospheric gas oil
(AGO) (Table 3.1). Fractionation is increased by reducing the partial pressures with the
aid of steam and a reboiler for Kerosene (Table 3.1). The pressure drop at top of the CDU
is 60 kPa with a top and bottom stage pressure of 15kPa and 160kPa, respectively.
Internal reflux has been ensured by the installation of three pumparounds as in Table 3.1.
Chapter3: Methodology 44

Figure 3. 6 KRC Products Balance Flow Chart (From KRC)

Chapter3: Methodology 45

Figure 3. 7 KRC Crude Distillation Unit (from This Work Results)

Chapter3: Methodology 46

Table 3.3 Side Stripper Specifications

Location
Side stripper (SS) between Stripped by Flow/Duty
trays

AGO 17 and 16 Steam 30 m3/h

Diesel 27 and 26 Steam 130m3/h

Kerosene 40 and 38 Reboiler 1.105e+007 kJ/h

Table 3.4 Pumparound Specifications

Location
Pump around (PA) between Duty (kW) Flow (kBPD)
trays

AGO 24 and 22 -3.7e+007 55

Diesel 36 and 34 3.7 e+007 55

Kerosene 50 and 48 -4.5 e+007 50

The bottom steam entering at tray 1 is exchanging heat twice, i.e. absorbing heat from the
liquid flowing down the trays and then exchanging heat with the upward flowing vapors,
entered at a rate 3300 kg/hr at 400 ˚C and 400 kPa.
Chapter3: Methodology 47

As mentioned in Chapter 2 the crude oil assay is essentially the chemical evaluation of
crude oil feed stocks by petroleum testing laboratories. Figure 3.8 and Table 3.5 represent
the typical crude assay report data. The distillation analysis of the crude oil sample was
carried out in accordance to ASTM D 2892 (15 Theoretical plate column). The yield
pattern of each fraction collected is tabulated in percentage weight and percentage
volume (APPENDIX A).

Table 3.5 Sample of Crude Oil General Tests for Year 2008

Test items Result

Density（15 0C, kg/m3) 865.5

API° 32.0

Viscosity（100 0C, mm2/s) 7.695

Solidification point, 0C 33

Carbon residue, m% 4.3

Water content, m% 0.2

Salt content，Total 5.3

Acid number, mgKOH/g 0.39

Sulfur content, wt% 0.057

Iron content, ppm 7.1

Calcium content, ppm 6.7

Chapter3: Methodology 48

Figure 3. 8 Sample of TBP Curve Recovery on Weight and Volume Percent

 Chapter 4

RESULTS AND DISCUSSION

4.1 Introduction

This chapter presents the results and discussion of the various parts of the work that were
conducted during the execution of this study. These include crude oil characterization,
simulation of PDF, assumption validation, retrofit measures (Effect of number of trays,
and feed try position), and adaptation measures results (effect of reflux ratio).

4.2 Crude Oil Characterization

The crude oil was characterized using the true boiling point (TBP) analysis methodology.
The characterization was conducted for the years 2006, 2007, 2008, 2009, and 2011. The
analysis was carried out by CPL and KRC. The sampling point was located at the inlet of
the crude distillation unit (CDU) tank farm and the sample was free of any disposal. The
Lab set apart wide range of fractions as naphtha, kerosene, diesel fraction, vacuum
distillation fraction, atmospheric distillation residue fraction and vacuum distillation
residue fraction by the true boiling point distillation instrument.

4.2.1 Property of Crude oil

The property analysis of the Nile Blend Crude for years 2006, 2007, 2008, 2009, and
2011 is summarized in Table 4.1. As shown in Table 4.1 there is a variation in all crude
oil properties. This can be attributed to the variation on time (years). This is because the
Chapter 4: Results and Discussion 50

crude oil varies with time as natural results of continuous reservoir depletion. And any
small differences in composition can greatly affect the physical properties and processing
required for producing salable products (Table 4.2).

Table 4.6 Properties of Nile Blend Crude

Test item 2006 2007 2008 2009 2011

Density, kg/m3 850.40 864.80 865.50 867.50 872.30

API° 34.81 32.04 32.00 31.60 30.58

Viscosity (at 100 0C) mm2/s - - 7.70 7.58 -

Pour point 0C 33.00 33.00 - 33.00 33.00

Water content，m% 0.09 0.75 0.20 0.50 0.60

Salt content, mgNaCl/L 5.00 - 5.30 8.06 9.00

Acid number mgKOH/g 0.23 0.40 0.39 0.59 0.52

Sulfur content, wt% 0.05 0.07 0.06 0.04 0.06

Asphaltenes, wt% 0.11 0.05 - - -

Chapter 4: Results and Discussion 51

4.2.1 Crude Oil Products Volume Percentage Yield

A summary of the product volume percentage yield from the crude assay reports for the
years 2006, 2007, 2008, 2009, and 2011 is represented in Table 4.7 and Figure 4.1. The
differences in the volume percentage amount can be attributed to the differences in the
feed characteristics (Table 4.1).

Table 4.7: Summary of Volume Percentage Yield of the Products with Years

Yield on crude ( vol. % )

Product
2006 2007 2008 2009 2011

Naphtha 11.30 9.60 6.63 7.22 13.27

Kerosene 10.40 8.90 7.98 8.45 6.58

Deisel 20.90 18.30 19.15 18.10 22.25

Residue > 350 ℃ 57.40 63.20 65.29 66.29 57.90

80

70
Yield on crude ( vol. % )

60

50
Naphtha
40
Kerosene
30 Deisel
Residue > 350 ℃
20

10

0
2005 2006 2007 2008 2009 2010 2011 2012
Years
Figure 4.1: Summary of Yield Percentage for the Products
 Chapter 4: Results and Discussion 52

4.3 Simulation of Refinery Process flow diagram (PFD)

Figure 4.2 shows the refinery process flow diagram simulated in Aspen HYSYS. The flow
diagram data have been taken from the Aspen Hysys Getting Started. The diagram consists of
a simple pre-heat train (heat exchanger, a desalter, two simple heaters and a pre-flash
separator) followed by a CDU. The feed to the CDU is preheated in a furnace. Crude oil at a
rate of 103 kilo barrel per day (kBPD) is fed to the pre-flash tower at a temperature at 175˚C
and a pressure of 540kPa. The pre-flash tower is responsible for separating the crude vapors
and liquid entering into the crude column as a bottom feed. This is carried out to reduce the
duty of the furnace to devise an economical process (Benali 2012). The furnace feed is the
bottom product of the pre-flash tower operating at a pressure drop of 250kPa with the crude
being heated to 400˚C.
Chapter 4: Results and Discussion 53

Figure 4.2 Process Flow Diagram of the Simulation Carried out in ASPEN HYSYS
Chapter 4: Results and Discussion 54

As shown in Figure 4.3 the column consists of 29 stages with a partial condenser,
three side strippers and three pumparounds. The heated crude is sent to in the tray 28.
Side strippers comprising 3 stages have been utilized for diesel and atmospheric gas
oil (AGO) (Table 4.4). The pressure drop at top of the CDU is 60 kPa with a top and
bottom stage pressure of 14kPa and 230kPa, respectively. Internal reflux has been
ensured by the installation of three pumparounds as in Table 4.3.
Chapter 4: Results and Discussion 55

Figure 4.3 Distillation Column Sub Flow Sheet from Hysys

Chapter 4: Results and Discussion 56

The bottom steam entering at tray 29 is exchanging heat twice, i.e. absorbing heat from
the liquid flowing down the trays and then exchanging heat with the upward flowing
vapors, entered at a rate 3400kg/hr at 194.6˚C and 1380kPa.

4.3.1 Hysys Program Validation

The program was validated by comparing CDU products data with the reference data
from HYSYS getting started module. The comparison results showed that there is no
significant difference in the liquid volume flow of the products (Table 4.3). This result
makes the Hysys program which was used in this research validated and trusted in order
to make the retrofit as well as the adaptation measurement.

Table 4.8 Comparison between Hysys Getting Started Module Results and this
Research Results

Liquid Volume Flow

Product Error Percentage
Hysys Results Research Results

Naphtha 150 149.99998 1.4E-05

Kerosene 62 61.99997 5.32E-05

Diesel 130 130.00010 4.77E-05

AGO 30 29.99999 2E-05

Chapter 4: Results and Discussion 57

4.4 Assumption validation

4.4.1 Influence of crude variation on product
Table 4.9 summarizes the laboratory results for crude oil products against API. The
results shown in this table make it clear that the API is decreasing with the years passage
of time i.e. as the number of years increased except for year 2006. Figure 4.4 represents
the products volume percentage yield against API. It is clear that the products yields are
not stable inspite of the fact that the apparatus units used in testing are the same. Changes
observed in products can most likely be due to the change in the specification of the crude
oil.

Table 4.9 Summary of Volume Percentage Yield of the Products with API
API 30.58 32.04 33.91 34.30 34.81
(Year) (2011) (2007) (2004) (2002) (2006)

Volume percentage yield

Product

Naphtha 14.10 9.53 11.29 10.85 11.73

Kerosene 7.80 8.94 9.68 10.41 10.12

Diesel 23.00 18.18 20.82 20.52 20.85

Residue 55.10 63.34 58.21 58.21 57.30

Summation 100.00 100.00 100.00 100.00 100.00

Chapter 4: Results and Discussion 58

70

60

50
Yeild volume %

40 Naphtha
Kerosene
30
Deisel
20 Residue
10

0
30 31 32 33 34 35
API
Figure 4.4 Volume Percentage Yield of the Products with API

4.4.2 Comparison between HYSYS simulation and true boiling point results
Figure 4.5 and Figure 4.6 represent a comparison study between Hysys simulation
program and laboratory (TBP) results for naphtha and residue product yield respectively
(See APPENDIX B). It is clear from the figures that there are no major differences in
results. It can be stated that both of them represent the ideal situation.

15

14

13
Yeild volume %

12
HYSYS
11
TBP
10

8
30 33 31 34 32 35
API
Figure 4.5 Volume Percentage Yield of Hysys Simulation and TBP Versus API for
Naphtha
Chapter 4: Results and Discussion 59

64
63
62
Yeild volume %

61
60
59
HYSYS
58
57 TBP
56
55
54
30 31 32 33 34 35
API

Figure 4.6 Volume Percentage Yield of Hysys Simulation and TBP Versus API for
Residue

The small difference between simulation and TBP can be attributed to the fact that the
simulation program is ideal situation, and the laboratory is more close to the reality
conditions comparing to simulation program.

4.4.3 Comparison between HYSYS simulation and KRC results

Results show high variation in weight percentage yield between KRC (refinery) and TBP
(laboratory) which indicate high losses in light product yield. Figure 4.7 shows that the
weight percentage yield of light product (naphtha) is always greater than in KRC,
whereas for heavy product (residue) the yield in Hysys is less than in KRC (Figure 4.8)
(See APPENDIX B).
Chapter 4: Results and Discussion 60

14.0

12.0

10.0
Weight %

8.0
KRC
6.0
HYSYS
4.0

2.0

0.0
30 31 32 33 34 35
API
Figure 4.7 Weight Percentage Yield of Hysys Simulation and KRC Versus API for
Naphtha

72.0

70.0

68.0
Weight %

66.0
KRC
64.0 HYSYS

62.0

60.0

58.0
30 31 32 API 33 34 35

Figure 4.8 Weight Percentage Yield of Hysys Simulation and KRC Versus API for
Residue

This variation means there are high losses in the production of the light product (naphtha)
in KRC, whereas high production of residue (which will be containing more useful
products) is produced.
Chapter 4: Results and Discussion 61

4.5 Retrofit Measures

4.5.1 Effect of Tray Numbers
The Aspen Hysys simulation program was used to study the effect of tray numbers on
naphtha and ATM residue volume percentage product. The number of trays has been
changed from 29 to59 with an increment of four stages. The results were analyzed using
the Microsoft Excel Program, as shown in Figure 4.9 and Figure 4.10.

0.122

0.121

0.120
Volume %

0.119

0.118 Naphtha

0.117

0.116

0.115
27 37 47 57 67
Tray numbers
Figure 4.9 Effect of Varying Number of Trays on Naphtha
Chapter 4: Results and Discussion 62

0.567

0.566

0.565

0.564
Volume %

0.563
ATM Residue
0.562

0.561

0.560

0.559
27 37 47 57 67
Tray Numbers

Figure 4.10 Effect of Varying Number of Trays on ATM Residue

The Results show that the liquid volume percent decreases with number of trays for
naphtha, whereas the percentage increased for ATM residue. This is because each
additional tray acts as an extra equilibrium contactor which will decrease the volume
production of naphtha. As the hotter vapor passes through the liquid on the tray above, it
transfers heat to the liquid. In doing so, some of the vapor condenses adding to the liquid
on the tray. The condensate, however, is richer in the less volatile components than is in
the vapor. Additionally, because of the heat input from the vapor, the liquid on the tray
boils, generating more vapor. This vapor, which moves up to the next tray in the column,
is richer in the more volatile components. This continuous contacting between vapor and
liquid occurs on each tray in the column and brings about the separation between low
boiling point components and those with higher boiling points (RWTUV, 2005). The
trays have been added from the top after the condenser stage.

Table 4.5 represents the expected volume percentage values for crude oil products taken
from the Hysys simulation program. These different values were depending on the crude
assay report for the Nile Blend Crude during different years.
Chapter 4: Results and Discussion 63

Table 4.10 The Expected Values of Volume Percentage from Hysys

API 32.47 API 33.91 API 34.30

Product
Volume Volume Volume
Volume % Volume % Volume %
Amount Amount Amount

Naphtha 13 89 11.3 79 10.9 77

Kerosene 11 76 9.6 68 10.5 74

Diesel 13 90 13.8 97 13.6 96

AGO 10 72 7.0 49 6.7 47

Residue 53 371 58.3 411 58.3 411

0.130

0.120

0.110

0.100
Volume %

0.090 API 32.47

0.080 API 33.91

0.070 API 34.30

0.060

0.050
27 32 37 42 47 52
Tray Numbers
Figure 4. 11 Effect of Varying Number of Trays on Naphtha via Different API
Values
Chapter 4: Results and Discussion 64

Figure 4.11 shows the variation of liquid volume percentage for Naphtha with number of
trays for different APIs. It is noticed from Figure 4.11 and Table 4.5 for all API values
with increasing number of trays the maximum amount that can be produced from
Naphtha will not be achieved this way. In order to maximize the volume percentage of
naphtha, it is recommended to reduce number of trays.

The efficiency of producing naphtha was found to be decreasing with increasing number
of trays as follow:

 For crude API 32.47: the efficiency was decreased from 96 to 92 for number of
trays varied from 29 to 45.

 For crude API 33.91: the efficiency was decreased from 61 to 53 for number of
trays varied from 29 to 45.

 For crude API 34.30: the efficiency was decreased from 66 to 58 for number of
trays varied from 29 to 45.

0.680

0.660

0.640
Volume %

0.620
API 32.47
0.600 API 33.91
0.580 API 34.30

0.560

0.540
27 32 37 42 47 52
Tray Numbers

Figure 4. 12 Effect of Varying Number of Trays on ATM Residue via different API
values
Chapter 4: Results and Discussion 65

Figure 4.12 shows the variation of liquid volume percentage for ATM Residue with
number of trays for different APIs. It is noticed from Figure 4.12 and Table 4.5 for all
API values with increasing number of trays the minimum amount that can be produced
from ATM Residue will not be achieved this way. It is recommended to reduce number of
trays in order to minimize the volume percentage for ATM Residue.

The efficiency of minimizing the production of ATM Residue was found to be decreasing
with increasing number of trays:

 For crude API 32.47: the efficiency was decreasing from 95 to 94 for number of
trays varied from 29 to 45.

 For crude API 33.91: the efficiency was decreasing from 93 to 92 for number of
trays varied from 29 to 45.

 For crude API 34.30: the efficiency was decreasing from 92 to 91 for number of
trays varied from 29 to 45.

4.5.2 Effect of Feed Tray Position

The Aspen Hysys simulation program was used to study the effect of feed tray position
on naphtha product. The feed tray position has been changed from 2, 3, 4, 9, 14, 19, 26,
and 36. The results were analyzed using the Microsoft Excel Program. Figure 4.13 and
Figure 4.14 represent the influence of varying feed tray position on the products
percentage yield.
Chapter 4: Results and Discussion 66

0.280
0.260
0.240
0.220
Volume %

0.200
0.180 Naphtha
0.160
0.140
0.120
0.100
1 11 21 31 41
Feed tray position
Figure 4.13 Effect of Varying Feed Tray Position on Naphtha

0.600
0.580
0.560
0.540
Volume %

0.520
0.500 ATM Residue
0.480
0.460
0.440
0.420
0.400
1 11 21 31 41
Feed tray position

Figure 4.14 Effect of Varying Feed Tray Position on ATM Residue

The results show that the liquid volume percent of naphtha increases with the feed tray
position increases, whereas the yield decreases for ATM residue. This is because as the
feed stage moves higher up the column, the top product becomes richer in the more
volatile components which will necessarily increase the volume product. In the mean time
the bottom contains less of the more volatile component, which will necessarily decrease
the volume of production (RWTUV, 2005).
Chapter 4: Results and Discussion 67

4.6 Adaptation Measures (Effect of Reflux Ratio)

Aspen Hysys simulation program was used to study the effect of reflux ratio on petroleum
products. The reflux ratio has been set to be 0.6, 0.7, 0.8, 0.9, and 1. The results were
analyzed using Microsoft excel program. Figure 4.15 and Figure 4.16 represent the
influence of varying reflux ratio on the volume percentage yield.

0.1500
0.1400
0.1300
Volume %

0.1200
0.1100
Naphtha
0.1000
0.0900
0.0800
0.45 0.6 0.75 0.9 1.05
Reflux ratio

Figure 4.15 Effect of Varying Reflux Ratio on the Naphtha

0.620
0.615
0.610
Volume %

0.605
0.600
0.595
ATM Residue
0.590
0.585
0.580
0.575
0.45 0.6 0.75 0.9 1.05
Reflux ratio

Figure 4.16 Effect of Varying Reflux Ratio on the ATM Residue

Chapter 4: Results and Discussion 68

The results clearly show that for naphtha with increasing the reflux ratio the volume
percentage decreased. However, for the ATM residue the volume percentage increased
with increasing the reflux ratio. This is due to the fact that increasing the reflux ratio will
lead to more liquid that is rich in the more volatile components which are being recycled
back into the column. Ultimately this turn of events will increase the separation
efficiency, but will decrease the volume production of naphtha and the vise verse for
residue (RWTUV, 2005).
 Chapter 5

CONCLUSION AND RECOMMENDATIONS

5.1 Conclusions

The objectives of this study are to characterize crude oil feed in order to simulate a
refinery distillation unit using Aspen Hysys programme and to investigate the influence
of crude oil variation on products, as well as design a new flexible distillation column
taking into consideration the retrofit measures (number of trays, and feed try position),
and adaptation measures (reflux ratio).

The crude oil and its products characterization results for years 2006, 2007, 2008, 2009,
and 2011 showed a clear variation in all properties. This can be attributed to the variation
on time (years). The refinery was successfully simulated and verified using Aspen Hysys
simulation program. This program was used to study the effect of varying API of crude
oil on the products. The results showed that the products yield was not stable. These
changes in products can be due to the changes in the specification of the crude oil.

The Hysys simulation results were compared with TBP and KRC results. The analysis
showed there were no differences in products yield between Hysys simulation and TBP
results. However, in KRC the results showed high variation in weight percentage yield in
that the weight percentage yield of light product (naphtha) was always greater than in
KRC, whereas for heavy product (ATM residue) the yield in Hysys was less than in KRC.
Chapter 5: Conclusion and Recommendations 70

Retrofit measures analysis was performed by studying the effect of tray numbers and feed
tray position on light and heavy volume percentage product. The Results showed that the
liquid volume percent decreased with number of trays for the light products (naphtha),
whereas the percentage increased for the heavy product (ATM residue). This is because
each additional tray acts as an extra equilibrium contactor which will decrease the volume
production of naphtha. The efficiency of producing naphtha was found to be decreasing
with increasing number of trays. For crude API 32.47 the efficiency was decreased from
96 to 92 for number of trays varied from 29 to 54, for crude API 33.91 the efficiency was
decreased from 61 to 53 for number of trays varied from 29 to 54, and for crude API
34.30 the efficiency was decreased from 66 to 58 for number of trays varied from 29 to
54. The efficiency of minimizing the production of ATM Residue was found to be
decreasing with increasing number of trays. For crude API 32.47 the efficiency was
decreasing from 95 to 94 for number of trays varied from 29 to 54, for crude API 33.91
the efficiency was decreasing from 93 to 92 for number of trays varied from 29 to 54, and
for crude API 34.30 the efficiency was decreasing from 92 to 91 for number of trays
varied from 29 to 54. It is recommended to reduce number of trays to maximize the
volume percentage of naphtha, and to minimize the volume percentage of ATM Residue.

The effect of feed tray position results showed that the liquid volume percent of light
products (naphtha) increases with the feed tray position decreases, whereas the yield
decreases for heavy product (ATM residue). This is because as the feed stage rises and
moves higher upwards, the top product becomes richer with the volatile components
which in turn will necessarily increase the volume product.

The adaptation measures showed that for the light products (naphtha) with increasing the
reflux ratio the volume percentage decreased. And for the heavy products (ATM residue)
the volume percentage increased with increasing the reflux ratio. This can be explained
by the fact that when the reflux ratio increases there would be more liquid and that the
rich volatile components are recycled back into the column.
Chapter 5: Conclusion and Recommendations 71

The main contribution resultant from the studies of this thesis is that it elucidates and
explains the influence of crude variation on products yield through time. Apart from this,
but an additional important contribution is that the study also presents the adaptation and
retrofit measures that affect the design of flexible distillation column.
Chapter 5: Conclusion and Recommendations 72

5.2 Recommendations and Future Work

During the course of executing this study various values in adaptation and retrofit
measures were used for studying their effects on the distillation column products.
However, in order to find the best parameter values for maximum product yield for
distillation column, it is recommended that future studies be carried out in a pilot plant.

The state of the feed mixture and feed composition may affect the operating procedures
and if the deviations from the design specifications are excessive, then the column may
no longer be able handle the separation task. So it is recommended to consider this factor
in future studies.
References 73

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Appendices 77

APPENDICES

APPENDIX A

 Sample of TBP data (2012):

Crude Oil General Tests

Test Name Test Method Unit Result

Density @15°C ASTM D5002 g/cm³ 0.8655

API ASTM D5002 - 31.84

-
S.G ASTM D5002 0.8663

TAN ASTM D664 mgKOH/g 0.44

Sulfur Content ASTM D4294 %m 0.0689

MCR ASTMD4530 Wt% 4.2

Appendices 78

True Boiling Point Distillation Data

Cut Yield Cum. Yield Cum.

Temp °C %Weight %Weight %Volume %Volume

IBP-65 0.39 0.39 0.24 0.24

65-80 1.22 1.61 1.50 1.74

80-95 1.25 2.86 1.50 3.24

95-110 0.73 3.58 0.86 4.10

110-125 0.09 3.67 0.10 4.20

125-140 0.75 4.42 0.88 5.08

140-155 0.70 5.12 0.81 5.89

155-170 1.28 6.40 1.47 7.36

170-185 0.40 6.80 0.44 7.81

185-200 2.96 9.76 3.26 11.07

200-230 2.53 12.29 2.78 13.85

230-245 1.94 14.23 2.10 15.95

245-260 2.16 16.39 2.31 18.26

260-275 2.28 18.67 2.41 20.67

275-290 2.26 20.93 2.39 23.05

290-305 1.46 22.39 1.53 24.59

Appendices 79

305-320 1.57 23.96 1.64 26.23

320-335 2.32 26.28 2.43 28.66

335-350 5.39 31.67 5.59 34.24

350-365 2.60 34.28 2.68 36.92

365-380 2.22 36.49 2.28 39.20

380+ 63.51 100.00 60.80 100.00

Appendices 80

Sample of TBP Curve Recovery on Weight and Volume Percent

Appendices 81

APPENDIX B

Yield on Mass Percentage for Naphtha in Crude Assay Report and KRC

Year Crude assay Ideal (m%) KRC Real (m%)

2007 4.98 4.46
2008 5.49 6.2
2009 5.99 4.87
2011 8.26 6.4

Yield on Mass Percentage for Kerosene in Crude Assay Report and KRC

Year Crude assay Ideal (m%) KRC Real (m%)

2007 8.27 4.47
2008 7.16 2.32
2009 7.6 3.8
2011 7.68 4.67

Yield on Mass Percentage for Diesel in Crude Assay Report and KRC

Year Crude assay Ideal (m%) KRC Real (m%)

2007 18 21.24
2008 18.22 22.63
2009 17.22 21.91
2011 16.12 18.97

Yield on Mass Percentage for ATM Residue in Crude Assay Report and KRC

Year Crude assay Ideal (m%) KRC Real (m%)

2007 65.15 69.47
2008 68.19 68.48
2009 69.19 69.07
2011 67.94 69.58
Appendices 82

Volume Percentage Yield of Hysys Simulation and TBP versus API

Yield of crude ( vol. % )

API 30.58 32.04 33.91 34.3 34.81

(Year) (2011) (2007) (2004) (2002) (2006)

TBP HYSY TBP HYSY TBP HYSYS TBP HYSYS TBP HYSYS

Naphtha 13.27 14.1 9.6 9.53 11.2 11.29 10.90 10.85 11.3 11.73

Kerosene 6.58 7.8 8.9 8.94 9.8 9.68 10.50 10.41 10.4 10.12

Diesel 22.25 23 18.3 18.18 20.6 20.82 20.40 20.52 20.9 20.85

Residue 57.9 55.1 63.2 63.34 58.4 58.21 58.20 58.21 57.4 57.3

Summation 100 100 100 100.0 100 100.0 100 100 100 100

Weight Percentage Yield of Hysys Simulation and KRC versus API

Yield of crude ( vol. % )

30.58 32.04 34.81

API
(2011) (2007) (2006)
(Year)

KRC HYSYS KRC HYSYS KRC HYSYS

Naphtha 6.6 12.0 4.7 7.6 5.3 9.6

Kerosene 4.7 6.0 4.5 6.1 5.3 7.2

Diesel 19.0 22.0 21.5 20.6 22.5 21.5

Residue 69.8 60.0 69.6 65.7 66.8 61.7

Summation 100 100 100 100 100 100

Appendices 83

Volume Percentage Yield of Naphtha from Hysys Simulation via different API
Volume Percentage Yield

Number of Trays API 32.47 API 33.91 API 34.30

29 12.17 7.99 7.24

33 12.01 8.08 6.95

37 11.89 8.29 6.75

41 11.80 8.43 6.60

45 11.73 8.54 6.47

49 11.67 8.62 6.37

Volume Percentage Yield of ATM Residue from Hysys Simulation via different API
Volume Percentage Yield
Number of Trays API 32.47 API 33.91 API 34.30

29 56.01 61.57 63.38

33 56.16 61.47 63.67

37 56.28 61.27 63.87

41 56.37 61.12 64.03

45 56.45 61.02 64.15

49 56.51 60.93 64.25

Appendices 84

APPENDIX C

 Effect of number of trays

No of trays Unit Off Gas Naphtha Kerosene Prod Diesel Prod AGO Prod ATM Residue

29 Volume Flow m3/h 0.000074 83.000288 55.000515 111.002316 51.001425 382.000509

Volume % 1E-07 0.122 0.081 0.163 0.075 0.560
Mass Flow kg/h 0.04992 59003.08939 42759.04972 90431.18296 42303.2961 335110.3869
33
Volume Flow m3/h 0.000038 81.930584 55.000119 111.000022 51.00006 383.076493
Volume % 5.57123E-08 0.120 0.081 0.163 0.075 0.562
Mass Flow kg/h 0.025686 58190.21075 42725.87978 90395.70174 42293.5628 336003.8594
37
Volume Flow m3/h 0.000003 81.124142 54.998752 111.002991 51.002083 383.881057
Volume % 4.39834E-09 0.119 0.081 0.163 0.075 0.563
Mass Flow kg/h 0.001774 57578.98503 42698.8978 90372.46247 42288.84188 336671.7587
41
Volume Flow m3/h 0.000003 80.500196 54.998367 111.003903 51.002712 384.505213
Volume % 4.39834E-09 0.118 0.081 0.163 0.075 0.564
Mass Flow kg/h 0.001687 58987.55252 42704.34125 90217.41398 42182.80943 335537.6081
Appendices 85

45 Volume Flow m3/h 0.000003 79.99867 54.998448 111.005137 51.00341 385.005843

Volume % 4.39834E-09 0.117 0.081 0.163 0.075 0.564
Mass Flow kg/h 0.001825 56726.66873 42662.50443 90337.92549 42281.03813 337605.2876
49
Volume Flow m3/h 0.000017 79.592717 54.998611 111.006108 51.003821 385.411169
Volume % 0.000 0.117 0.081 0.163 0.075 0.565
Mass Flow kg/h 0.011082 56419.34871 42649.69388 90325.49955 42278.17811 337941.624
59
Volume Flow m3/h 0.000108 78.844032 54.99945 110.998907 50.999493 386.172202
Volume % 0.000 0.116 0.081 0.163 0.075 0.566
Mass Flow kg/h 0.072713 55852.68254 42626.65484 90294.97323 42268.604 338573.1141
Appendices 86

 Effect of varying feed tray position

Tray position Unit Off Gas Naphtha ATM Residue AGO Prod Diesel Prod Kerosene Prod

2
Volume Flow m3/h 0.000076 79.649985 410.179566 50.000031 84.000085 73.0002
Volume % 0.000 0.114 0.589 0.072 0.121 0.105
Mass Flow kg/h 0.050635 57357.34375 372214.5552 43485.04808 69634.10867 57457.59

3
Volume Flow m3/h 0 84.060932 405.782797 50.000022 84.001247 73.00002
Volume % 0.000 0.121 0.582 0.072 0.121 0.105
Mass Flow kg/h 0.000021 60717.40807 368791.9602 43417.04199 69652.9037 57584.43
4
Volume Flow m3/h 0.000017 86.000002 403.849872 49.999991 83.999993 73
Volume % 0.000 0.123 0.579 0.072 0.121 0.105
Mass Flow kg/h 0.011586 62198.51889 367290.0068 43377.98966 69657.34946 57644.71
9
Volume Flow m3/h 0.000014 89.451668 400.402951 50.000013 84.000213 72.99994
Volume % 0.000 0.128 0.575 0.072 0.121 0.105
Mass Flow kg/h 0.009555 64840.57389 364579.2017 43300.66333 69685.23384 57767.81
Appendices 87

14
Volume Flow m3/h 0.000016 91.909436 397.946994 49.999552 83.999787 72.99989

Volume % 0.000 0.132 0.571 0.072 0.121 0.105

Mass Flow kg/h 0.010709 66730.826 362481.3142 43360.92786 69740.1714 57861.13
19
Volume Flow m3/h 0.000015 97.607024 392.247484 50.000661 83.999742 73.00015
Volume % 0.000 0.140 0.563 0.072 0.121 0.105
Mass Flow kg/h 0.010101 71146.98676 355526.357 45494.96104 69943.81364 58061.64
26
Volume Flow m3/h 0.000005 154.505307 335.339866 50.000184 84.000338 72.99903
Volume % 0.000 0.222 0.481 0.072 0.121 0.105
Mass Flow kg/h 0.003285 116153.1387 302747.1786 45223.77175 76062.45145 59976.9
36
Volume Flow m3/h 0.000006 186.249173 303.589767 49.999925 83.999862 73.00031
Volume % 0.000 0.267 0.436 0.072 0.121 0.105
Mass Flow kg/h 0.004127 141888.4886 275297.9528 45374.48501 76267.41669 61329.43
Appendices 88

 Effect of Varying Number of Trays and API on Volume Percentage

API 32.47
No
ATM Kerosene Diesel AGO ATM
of Unit Off Gas Naphtha
Feed Prod Prod Prod Residue
Tray

29
Volume Flow m3/h 682.0758 0.000074 83.0003 55.000515 111.002316 51.001425 382.000509
% 1E-07 0.122 0.081 0.163 0.075 0.560

33
Volume Flow m3/h 682.0758 0.000038 81.9306 55.000119 111.000022 51.00006 383.076493
% 5.57123E-08 0.120 0.081 0.163 0.075 0.562

37
Volume Flow m3/h 682.0758 0.000003 81.1241 54.998752 111.002991 51.002083 383.881057
% 4.39834E-09 0.119 0.081 0.163 0.075 0.563

41
Volume Flow m3/h 682.0758 0.000003 80.5002 54.998367 111.003903 51.002712 384.505213
% 4.39834E-09 0.118 0.081 0.163 0.075 0.564
Appendices 89

45
Volume Flow m3/h 682.0758 0.000003 79.99867 54.998448 111.005137 51.00341 385.005843
% 4.39834E-09 0.117 0.081 0.163 0.075 0.564

49
Volume Flow m3/h 682.0758 0.000017 79.59272 54.998611 111.006108 51.003821 385.411169
% 0.000 0.117 0.081 0.163 0.075 0.565
Appendices 90

API 33.91

No of
Unit ATM Feed Off Gas Naphtha Kerosene Prod Diesel Prod AGO Prod ATM Residue
Trays

29
Volume Flow m3/h 702.996277 0.000001 48.827 67.999846 97.00056 48.996461 440.137536
% 0.000 0.069 0.097 0.138 0.070 0.626

33
Volume Flow m3/h 702.996277 0.000003 46.771931 68.000914 97.000381 49.000004 442.190362
% 0.000 0.067 0.097 0.138 0.070 0.629
37
Volume Flow m3/h 702.996277 0.000003 45.219063 68.003324 96.999918 49.000093 443.742873
% 0.000 0.064 0.097 0.138 0.070 0.631
41
Volume Flow m3/h 702.996277 0.000003 44.01544 68.001274 97.000071 48.999999 444.949824
% 0.000 0.063 0.097 0.138 0.070 0.633
45
Volume Flow m3/h 702.996277 0.000003 43.060764 67.998777 97.000102 48.999877 445.908177
% 0.000 0.061 0.097 0.138 0.070 0.634
49
Volume Flow m3/h 702.996277 0.000002 42.285338 67.999527 97.000114 48.999933 446.683684
% 0.000 0.060 0.097 0.138 0.070 0.635
Appendices 91

API 34.30

No of Kerosene Diesel ATM

Unit ATM Feed Off Gas Naphtha AGO Prod
Trays Prod Prod Residue

29
Volume Flow m3/h 704.651152 0 51.012599 72.9959 83.986248 49.99159 446.630639
% 0.000 0.072 0.104 0.119 0.071 0.634

33
Volume Flow m3/h 704.651152 0.000003 48.9884 72.994306 83.985516 49.991177 448.659493
% 0.000 0.070 0.104 0.119 0.071 0.637

37
Volume Flow m3/h 704.651152 0.00001 47.554918 72.999732 83.999182 49.999569 450.066936
% 0.000 0.0675 0.104 0.119 0.071 0.639

41
Volume Flow m3/h 704.651152 0.000001 46.482377 72.993325 83.987623 49.992262 451.165894
% 0.000 0.0660 0.104 0.119 0.071 0.640

45
Volume Flow m3/h 704.651152 0 45.611608 72.99402 83.987583 49.991993 452.037205
% 0.000 0.0647 0.104 0.119 0.071 0.642

49
Volume Flow m3/h 704.651152 0.000001 44.887394 452.761497 49.991807 83.988147 452.761497
% 0.000 0.0637 0.643 0.071 0.119 0.643
Appendices 92

 Effect of Reflux Ratio

Reflux Ratio = 0.5

Unit Naphtha ATM Residue AGO Prod Diesel Prod Kerosene Prod

Temperature C 20.59033 355.680364 325.1625 257.398082 233.195368

Pressure kPa 14 230 184.117647 153.529412 116.823529
Molar Flow kgmole/h 637.1173 791.882146 122.65233 272.328836 313.735051
Mass Flow kg/h 69481.4 358888.9909 43708.1471 70067.89513 58018.66562
Liquid Volume Flow m3/h 95.45438 394.390577 50.000527 84.002228 72.998657
Heat Flow kJ/h -1.5E+08 -464122371.5 -60368308 -110904907 -95994021.62
Volume % 1.4E-01 5.7E-01 7.2E-02 1.2E-01 1.0E-01

Reflux Ratio = 0.6

Unit Naphtha ATM Residue AGO Prod Diesel Prod Kerosene Prod

Temperature C 19.57873 355.6936 321.21224 252.426845 225.845958

Pressure kPa 14 230 184.117647 153.529412 116.823529
Molar Flow kgmole/h 602.4166 807.285245 126.569983 279.282701 322.300568
Mass Flow kg/h 64182.49 364996.2471 43462.8279 69773.02869 57753.01872
Liquid Volume Flow m3/h 88.59115 401.257545 49.999925 84.000175 73.000106
Heat Flow kJ/h -1.4E+08 -471972576.7 -60542061 -111469553.4 -96795710.66
Volume % 1.3E-01 5.8E-01 7.2E-02 1.2E-01 1.0E-01
Appendices 93

Reflux Ratio = 0.7

Unit Naphtha ATM Residue AGO Prod Diesel Prod Kerosene Prod

Vapour Fraction 0.000003 0 0 0 0

Temperature C 18.59531 355.657059 317.88131 247.747991 218.73399
Pressure kPa 14 230 184.117647 153.529412 116.823529
Molar Flow kgmole/h 571.0063 821.232327 129.569856 285.81004 330.360765
Mass Flow kg/h 59639.99 370228.4927 43285.1025 69506.6358 57509.62767
Liquid Volume Flow m3/h 82.65713 407.194399 49.999157 84.000107 73.000352
Heat Flow kJ/h -1.3E+08 -478744656.7 -60730180 -112010720.8 -97572548.16
Volume % 1.2E-01 5.8E-01 7.2E-02 1.2E-01 1.0E-01

Reflux Ratio = 0.8

Unit Naphtha ATM Residue AGO Prod Diesel Prod Kerosene Prod

Vapour Fraction 0.000002 0 0 0 0

Temperature C 17.66663 355.589294 315.023404 243.868101 213.154419
Pressure kPa 14 230 184.117647 153.529412 116.823529
Molar Flow kgmole/h 543.1443 833.926078 131.982086 291.672399 337.365176
Mass Flow kg/h 55641.6 374810.9213 43148.842 69271.07122 57299.40984
Liquid Volume Flow m3/h 77.42764 412.425732 49.999954 83.999868 72.999949
Heat Flow kJ/h -1.2E+08 -484715178.9 -60912948 -112432483.5 -98139707.06
Volume % 1.1E-01 5.9E-01 7.2E-02 1.2E-01 1.0E-01
Appendices 94

Reflux Ratio = 0.9

Unit Naphtha ATM Residue AGO Prod Diesel Prod Kerosene Prod
Vapour Fraction 0 0 0 0 0
Temperature C 16.78297 355.532342 312.473411 240.734973 206.856013
Pressure kPa 14 230 184.117647 153.529412 116.823529
Molar Flow kgmole/h 518.0929 844.702681 134.147191 296.656632 344.585774
Mass Flow kg/h 52291.33 378692.6252 43026.8318 69073.82576 57088.95016
Liquid Volume Flow m3/h 72.9964 416.858477 49.999991 84.000118 72.999873
Heat Flow kJ/h -1.2E+08 -489773644.7 -61073083 -112759050.1 -98806739.72
Volume % 1.0E-01 6.0E-01 7.2E-02 1.2E-01 1.0E-01

Reflux Ratio = 1
Unit Naphtha ATM Residue AGO Prod Diesel Prod Kerosene Prod
Vapour Fraction 0 0 0 0 0
Temperature C 15.92391 355.426832 309.936235 237.751818 201.589484
Pressure kPa 14 230 184.117647 153.529412 116.823529
Molar Flow kgmole/h 494.9658 854.911563 135.982036 301.264854 351.14856
Mass Flow kg/h 49238.39 382216.271 42925.7079 68895.08967 56899.67647
Liquid Volume Flow m3/h 68.94979 420.906866 49.999819 83.999937 73.000032
Heat Flow kJ/h -1.1E+08 -494430758.9 -61258225 -113080155.7 -99332747.48
Volume % 9.9E-02 6.0E-01 7.2E-02 1.2E-01 1.0E-01
Appendices 95

APPENDIX D

General properties of petroleum distillates

 Liquefied Petroleum Gas

The gases obtained from crude oil distillation are ethane, propane, and n-butane
isobutene. These products cannot be produced directly from the crude distillation and
require high-pressure distillation of overhead gases from the crude column. C 3 and C4
particularly are recovered and sold as liquefied petroleum gas (LPG), while C 1 and C2 are
generally used as refinery fuel.

 Naphtha

C5-400°F ASTM cut is generally termed naphtha. There are many grades and boiling
ranges of naphtha. Many refineries produce 400 °F end-point naphtha as an overhead
distillate from the crude column, and then fractionate it as required in separate facilities.
Naphtha is used as feedstock for petrochemicals either by thermal cracking to olefins or
by reforming and extraction of aromatics. Also some naphtha is used in the manufacture
of gasoline by a catalytic reforming process.

 Kerosene

The most important use of kerosene is as aviation turbine fuel. This product has the most
stringent specifications, which must be met to ensure the safety standards of the various
categories of aircraft. The most important specifications are the flash and freeze points of
this fuel. The initial boiling point (IBP) is adjusted to meet the minimum flash
requirements of approximately 100°F. The final boiling point (FBP) is adjusted to meet
the maximum freeze point requirement of the jet fuel grade, approximately -52°F. Full-
range kerosene may have an ASTM boiling range between 310 and 550°F Basic civil jet
fuels are:
Appendices 96

1. Jet A, a kerosene-type fuel having a maximum freeze point of -40°F Jet A-type fuel is
used by mainly domestic airlines of various countries, where a higher freeze point
imposes no operating limitations.
2. Jet A-1, a kerosene-type fuel identical with Jet A but with a maximum freeze point of
-47°F. This type of fuel is used by most international airlines. Jet A and Jet A-1
generally have a flash point of 38°F.
3. Jet B is a wide-cut gasoline-type fuel with a maximum freeze point of -50 to -58°F.
The fuel is of a wider cut, comprising heavy naphtha and kerosene, and is meant
mainly for military aircraft.

 Diesel

Diesel grades have an ASTM end point of 650-700°F Diesel fuel is a blend of light and
heavy distillates and has an ASTM boiling range of approximately 350-675°F Marine
diesels are a little heavier, having an ASTM boiling end point approximately 775°F. The
most important specifications of diesel fuels are cetane number, sulfur, and pour or cloud
point. Cetane number is related to the burning quality of the fuel in an engine. The
permissible sulfur content of diesel is being lowered worldwide due to the environmental
pollution concerns resulting from combustion of this fuel. Pour point or cloud point of
diesel is related to the storage and handling properties of diesel and depends on the
climatic conditions in which the fuel is being used.

 Vacuum Gas Oil

Vacuum gas oil is the distillate boiling between 700 and 1000°F. This is not a saleable
product and is used as feed to secondary processing units, such as fluid catalytic cracking
units, and hydrocrackers, for conversion to light and middle distillates.
Appendices 97

 Residual Fuel Oil

Hydrocarbon material boiling above I000 °F is not distillable and consists mostly of
resins and asphaltenes. This is blended with cutter stock, usually kerosene and diesel, to
meet the viscosity and sulfur specifications of various fuel oil grades.

 Vacuum distillation products

In an atmospheric distillation tower, the maximum flash zone temperature without

cracking is 700-800°F. The ATM residue, commonly known as reduced crude, contains a
large volume of distillable oils that can be recovered by vacuum distillation at the
maximum permissible flash zone temperature. The TBP cut point between vacuum gas
oil and vacuum residue is approximately 1075-1125°F. The cut point is generally
optimized, depending on the objectives of the vacuum distillation, into asphalt operation
and pitch operation.

 Asphalt Operation

Given the specification of the asphalt (penetration) to be produced, the corresponding

residuum yield can be determined from the crude assay data. In asphalt operation, some
gas oil must remain in the pitch to provide the proper degree of plasticity. Not all crudes
can be used to make asphalt.

Experimental data for asphalt operation are necessary to relate asphalt penetration to
residual volume. The penetration range between 85 and 10, are possible and the units are
generally designed to produce more than one grade of asphalt.

The principal criteria for producing lube oil fractions are viscosity, color, and rejection to
residuum the heavy impurities and metals. These oils are further refined by solvent
extraction, dewaxing, and other types of finishing treatment, such as hydrotreating.

Resorcinol crystallizes from benzene as colorless needles which are readily soluble in
Appendices 98

water, alcohol and ether, but insoluble in chloroform and carbon disulfide. Resorcinol (or
resorcin) is a chemical compound from the dihydroxy phenols. It is the 1,3-isomer of
benzenediol. It is also known with a variety of other names, including: m-
dihydroxybenzene, 1,3-benzenediol, 1,3-dihydroxybenzene, 3-hydroxyphenol, m-
hydroquinone, m-benzenediol, and 3-hydroxycyclohexadien-1-one.