gas

2021

COMBATING OPTIMISED
HEAT STABLE SYNGAS
SALTS PRODUCTION
OFFSHORE GAS CONTROLLING
PROCESSING GAS FIRED
REHEATERS
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 FROM
WELLHEAD
TO
CONSUMER
Honeywell UOP has a comprehensive portfolio of advanced
technologies for gas processing, including separations,
purification, liquefaction, and carbon sequestration.
Reach peak performance and respond quickly to changing
market conditions with modular solutions for greater speed,
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Welcome to the Future of Gas Processing

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 ptq gas
PETROLEUM TECHNOLOGY QUARTERLY

2021
www.digitalrefining.com

3 The blue bridge

Chris Cunningham

Clay Jones and Harnoor Kaur Optimized Gas Treating
Elmo Nasato Nasato Consulting

11 Stable vessel design for FLNG

Lars Odeskaug and Saeid Mokhatab
Front Energy AS

17 Cleaning amine units cost effectively

Marcello Ferrara and Domenico Ferrara
ITW

25 The case for blue hydrogen

Tarun Vakil and Marco Márquez
MATHESON, a subsidiary of Nippon Sanso
Holdings Corporation

35 Monitoring gas emissions

Mark Calvert and Sangwon Park
Servomex

38 Getting the most out of syngas

Claudia Von Scala and Natalia Molchanova
Sulzer Chemtech

Cover
At 42 billion m3/y capacity, Gazprom’s Amur site near Russia’s border with China will be
one of the world’s largest gas processing plants
Photo: Gazprom

©2021. The entire content of this publication is protected by copyright full details of which are available from the publishers. All rights
reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means –
electronic, mechanical, photocopying, recording or otherwise – without the prior permission of the copyright owner.
The opinions and views expressed by the authors in this publication are not necessarily those of the editor or publisher and while every
care has been taken in the preparation of all material included in Petroleum Technology Quarterly and its supplements the publisher
cannot be held responsible for any statements, opinions or views or for any inaccuracies.

ed com copy 3.indd 1 18/03/2021 13:56

ipco.indd 1
IPCO_PTQ_Refinery_210x297.indd 1 17/03/2021 12:24
18.02.2020
 ptq
PETROLEUM TECHNOLOGY QUARTERLY
The blue bridge

L
Editor ast July, the European Commission (EC) announced its grand plan for
Chris Cunningham a zero carbon future for the European Union’s industrial base – power,
editor@petroleumtechnology.com heavy industry, and potentially the transport sector. The target is no-carbon
hydrogen production based on electrolysis of water while the energy to drive
Production Editor
a generation of electrolysers would be produced by renewable generators,
Rachel Storry
production@petroleumtechnology.com chiefly wind and solar. The schedule for this scheme envisages zero carbon
activity by 2050.
Graphics Sectors like chemicals, steel, aviation, and heavy road transport are resis-
Peter Harper tant to electrification. They need to burn fuel which, in the main, means
graphics@petroleumtechnology.com natural gas and refined petroleum liquids. The EC sees hydrogen as an obvi-
ous means to replace fossil fuels from the energy slate which in turn implies
Editorial
a gathering cloud over the natural gas industry.
tel +44 844 5888 773
fax +44 844 5888 667 Of course there are a few technical issues to resolve along the way to a
zero carbon Europe. For instance, there will need to be a huge expansion of
Business Development Director renewable power generation, and the means to store that power when gener-
Paul Mason ation at source is interrupted by weather conditions. Electrolysers which
sales@petroleumtechnology.com produce hydrogen on a scale that could keep industry ticking over are some
way from development, although the general view is that this could be
Advertising Sales Office
resolved by the end of the current decade.
tel +44 844 5888 771
fax +44 844 5888 662 There are also regulatory issues for the EC to resolve. It is an article of
faith for Brussels that gas producers and operators of transmission networks
Managing Director must not be one and the same. This is a central tenet of EU competition
Richard Watts policy that would need to be resolved to fit a very different production and
richard.watts@emap.com distribution system.
Despite the surrounding issues, three decades or so does not seem an
Circulation
unreasonable timeframe to achieve a version of a ‘carbon free’ future for
Fran Havard
circulation@petroleumtechnology.com many sectors of industry. Meanwhile, the apparent cloud over the natural
gas industry has a silver lining. Last summer, the EC conceded that a supply
EMAP, 10th Floor, Southern House, of green hydrogen – the kind produced by electrolysis – is unlikely to meet
Wellesley Grove, Croydon CR0 1XG its carbon-free ambitions. At the end of January this year, the European
tel +44 208 253 8695 Parliament, the elected branch of the EU’s executive, voted to support hydro-
gen derived from fossil fuel – blue hydrogen – as a bridge to zero carbon in
what would meanwhile be a lower carbon future.
Register to receive your regular copy of
PTQ at www.eptq.com/register Most hydrogen produced in the world is derived from natural gas, and
most of that is the product, along with carbon dioxide, of steam methane
PTQ (Petroleum Technology Quarterly) (ISSN reforming (SMR) which supplies hydrogen for refinery processes including
No: 1632-363X, USPS No: 014-781) is published
quarterly plus annual Catalysis edition by EMAP and cracking and desulphurisation. Blue hydrogen is the SMR kind, along with
is distributed in the US by SP/Asendia, 17B South some from autothermal reforming, with added carbon capture, storage and/
Middlesex Avenue, Monroe NJ 08831. Periodicals
postage paid at New Brunswick, NJ. Postmaster: or utilisation.
send address changes to PTQ (Petroleum Technology
Quarterly), 17B South Middlesex Avenue, Monroe NJ
The combined capacity of Europe’s fleet of SMR units is a long way from
08831. Back numbers available from the Publisher supplying even a minor portion of the level of hydrogen production targeted
at $30 per copy inc postage.
for 2050. By implication, there would be some compensation for the natural
gas industry’s proposed loss of markets, certainly for the foreseeable future.
And it is looking like boom time for the construction of new SMR units.

CHRIS CUNNINGHAM

Gas 2021 3

ed com copy 3.indd 2 18/03/2021 13:55

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 Acid gas fired reheater control
Operating as close as possible to the stoichiometric air-to-fuel ratio is advised for acid
gas fired reheaters

CLAY JONES and HARNOOR KAUR Optimized Gas Treating

ELMO NASATO Nasato Consulting

M
odified Claus based sul- gas). One part of this control strat- not identical. One of the primary
phur recovery units (SRUs) egy is determined by the amount of objectives for the TR is to create the
require successive cooling heat release needed to achieve the stoichiometric amount of SO2 that
and reheating of the process gas desired temperature rise in the pro- will allow the overall conversion of
stream as it passes through several cess stream: this temperature sets H2S to elemental sulphur to proceed
catalytic converter stages. Between the total amount of H2S combustion as far as possible through the Claus
each converter, the gas is cooled needed in the reheater. reaction (Equation 1). This objective
to condense and remove elemen- After the temperature require- causes the optimal H2S:SO2 ratio in
tal sulphur, then reheated to allow ment is set, there is still a degree of the TR to be close to 2:1 to match
production of additional elemen- freedom left in the control philoso- Claus reaction stoichiometry. In
tal sulphur in the next stage. Figure phy: should we feed the stoichio- contrast, the primary process objec-
1 shows a typical three-converter metrically required amount of acid tive in a fired reheater is simply to
configuration. gas such that it is all burned, should liberate enough heat of combustion
There are several common meth- we feed an excess amount of acid with a stable flame to achieve the
ods to reheat the stream including gas so that the combustion products required temperature increase in the
indirect steam heat, electric heat- contain a 2:1 ratio of H2S:SO2, or process stream.
ers, hot oil, gas/gas, and direct- does the best answer lie somewhere 3
fired reheaters. This article focuses between these two approaches? 2 𝐻𝐻$ 𝑆𝑆 + 𝑆𝑆𝑂𝑂$ ↔ 𝑆𝑆$ + 2 𝐻𝐻$ 𝑂𝑂 [1]
2
on direct-fired reheaters which Here we use a rate-based simulation
use some of the SRU’s acid gas to explore the process implications As per the TR flame control strat-
feed as fuel. Acid gas fired reheat- of this choice. Specifically, the ques- egy, in order to maintain reliable
ers (AGFR) are burners positioned tion to be answered is what effect AGFR operation, it is imperative
between the sulphur condenser does the reheater’s air-to-acid-gas to have a proper air control system
and the next converter bed. The hot ratio have on overall sulphur recov- that maintains flame stability to sat-
combustion gases from the burner ery and COS generation? isfy the required temperature con-
are mixed with the main process trol setpoint. The control scheme
stream in order to heat it to the Process description should be programmed to allow
desired converter temperature. The chemistry pertaining to AGFRs for independent feed flow meas-
Since these reheaters are burners, is generally similar to chemistry urement on all feed streams to the
they require a strategy to control in the SRU thermal reactor (TR), AGFR burner; this includes amine
the flow rate of air and fuel (acid although the process objectives are acid gas and, where applicable,

Amine
acid gas
Fired reheater-1 Fired reheater-2 Fired reheater-3

SWS
acid gas
Thermal reactor
Converter-1 Converter-2 Converter-3 To TGU
Oxygen
WHB
Molten
Air Condenser-1 Condenser-2 Condenser-3 Condenser-4 Sulphur

Air blower

Figure 1 Flowsheet for case study

www.digitalrefining.com Gas 2021 5

gas ogt.indd 1 17/03/2021 12:36

 Flowsheet operating conditions for case study present study we will use Claus as
a proxy for all of them. The extent
Amine acid gas feed rate 450 lbmol/h of Claus conversion taking place in
Amine acid gas composition Test Run 1 composition Test Run 2 composition a reheater depends on the size and
(wet basis) (wet basis)
configuration of the equipment. If
H2S = 92% H2S = 83%
CO2 = 5% CO2 = 14% the residence time is long enough,
CH4 = 0.5 CH4 = 0.5 the reaction will proceed to equilib-
SWS gas feed rate 81 lbmol/h rium. Conversely, if the residence
BTEX composition in SWS 1900 ppmv
time is very short, the Claus reac-
Oxygen enrichment 29%
Outlet temperature of 1st sulphur converter 650°F tion may not occur to any apprecia-
Outlet temperature of 2nd sulphur converter ~ 485°F* ble extent.
Outlet temperature of 3rd sulphur converter ~ 420°F* Our study starts with a base case
*Temperatures of 2nd and 3rd converters set to maintain 25°F approach to sulphur dew point temperature which is burning enough H2S to
achieve the temperature targets for
Table 1 the unit operation. The amount of
acid gas fed to the burner (% stoi-
all fuel gas streams with steam date most of the acid gas fed to the chiometric air-to-fuel ratio) is varied
moderation cascaded to fuel gas SRU and provide enough residence along with the extent that the Claus
flow. Each feed stream will have time such that slower reactions reaction is allowed to proceed.
an air demand multiplier that can (including the Claus reaction) can The primary design and operating
be adjusted based on composi- approach thermodynamic equilib- decisions discussed in this article
tion in order to provide the total rium. Since fired reheaters will typ- address the question as to whether
flow target dependent on the cas- ically take only a small percentage the air and acid gas should be fed
cade temperature control setpoint. of the total acid gas flow, they are in stoichiometric proportions, or
Air demand requirement for each designed with much shorter resi- should the acid gas be fed in excess?
stream is then fed to a summation dence times. As a consequence of How much does the design of the
block to allow for ratio air control. shorter residence time, kinetically particular reheater vessel influence
In gas plants, it is common to have controlled reactions (such as the this decision?
lean amine acid gas with less than Claus reaction) will not typically
50% H2S. For lean amine acid gas be able to achieve equilibrium in a Case study
and/or turndown operation (refin- fired reheater before the hot gases The case study is based on a typical
ery applications included), it may are cooled by mixing with the main refinery SRU (see Figure 1). The unit
be necessary to co-fire the burners process stream. feed and operating conditions are
with supplemental fuel gas to sus- In reality there are several kinet- shown in Table 1. Two amine acid
tain a stable flame. ically controlled reactions tak- gas compositions were used: Test
Another important difference ing place in AGFRs in addition to Run 1 with 92% H2S and Test Run 2
from the TR is vessel size and resi- Claus: for example, thermal split- with 83% H2S. The model includes
dence time. TRs typically accommo- ting of H2S into H2 and S2. For the only the conversion section of the
SRU. It does not include the tail gas
treating unit (TGTU).
To explore the process implica-
tions of reheater operation, we ran
3200 Refractory damage a rate based sulphur plant simu-
Reheater flame temperature, ˚F

lation in SulphurPro with varying

O2 breakthrough
Flame instability

2700 burn strategies from 30% to 90%

of stoichiometric air-to-fuel ratio.
The heat release requirement for a
2200 reheater does not change very much
Safe operating range with burn strategy. Therefore, the
air supply to each reheater also does
1700
not change very much; instead, we
change the amount of excess acid
1200 gas sent to the reheater beyond the
10 30 50 70 90 amount required to consume all the
% Stoichiometric air-to-acid gas ratio oxygen.
It is difficult to know the extent of
Figure 2 Reheater flame temperature changes with burn strategy. Green lines represent Claus conversion that will occur in a
cases with no Claus reaction. Blue lines represent cases with Claus reaction proceeding reheater because it is a strong func-
to equilibrium. Solid lines represent Test Run 1 with higher H2S concentration in amine tion of the size and configuration of
acid gas. Dashed lines represent Test Run 2 with lower H2S concentration. Shaded region the equipment. From a modelling
indicates approximate safe operating range
perspective, the uncertainty was

6 Gas 2021 www.digitalrefining.com

gas ogt.indd 2 17/03/2021 12:36

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 peratures. Note that for this case
98% 92%
study, air-to-acid-gas ratios above
50% lead to flame temperatures that
can result in refractory and burner
Sulphur recovery with 92% H2S

Sulphur recovery with 83% H2S

damage.
97% 91%
Effect on sulphur recovery
Perhaps the most important obser-
vation from this study is that the
96% 90% reheater burn strategy can affect
the overall recovery of the conver-
sion section of the SRU. As Figure 3
shows, changing the reheater burn
95% 89% strategy can lead to an almost 0.5%
20 40 60 80 100 loss in sulphur recovery, forcing a
% Stoichiometric air-to-acid gas ratio larger work load onto the TGTU.
(Recall that the TGTU has to han-
Figure 3 Sulphur recovery changes with burn strategy. Green lines represent cases dle all of the unrecovered sulphur.
with no Claus reaction. Blue lines represent cases with Claus reaction proceeding to Dropping sulphur recovery from
equilibrium. Solid lines represent Test Run 1 with higher H2S concentration in amine acid 97.3 to 96.9% means an increase
gas. Dashed lines represent Test Run 2 with lower H2S concentration from 2.7 to 3.1% not recovered,
or 15% more sulphur load to the
bounded by running the models in Effect on flame temperature TGTU.) The cause of this effect is
two different reaction modes to rep- The most immediate result of differ- that unconverted and unburned acid
resent the two limiting cases. One ing air-to-fuel ratio in the reheater gas passing through the reheater is
limiting case allows all reactions is on the adiabatic flame tempera- fed to the third sulphur converter
to come to equilibrium by Gibbs ture (see Figure 2). As expected, the which then has more work to do. In
energy minimisation which sim- hottest temperature is at the sto- the unusual circumstance where the
ulates a large reheater with a resi- ichiometric air-to-fuel ratio since reheaters are large enough to allow
dence time of 0.5 seconds or more. deviation from this ratio implies the the Claus reaction to come to equi-
The other limiting case prevents the presence of additional unreacted librium this will not be a significant
Claus reaction from occurring at all, gas which will act as a heat sink. effect, as shown by the converging
representing a small reheater with a The Claus reaction is endothermic lines at the right-hand side of both
residence time of 0.1 second or less. at flame temperatures, so models Figure 3 and Figure 4. As discussed,
The behaviour of a real reheater is which inhibit the Claus reaction most real plants will lie somewhere
bounded by these two extremes. show slightly higher flame tem- between the two extremes shown in
these plots.

Effect on COS sent to TGTU

130
A final conclusion relates to the
120
amount of COS that reaches the
110 TGTU. In sulphur plants, COS is an
100 undesired by-product created when
90 hydrocarbons are present while acid
80 gas is being burned. Depending on
catalyst and operating conditions,
COS, ppmv

70
an appreciable amount of COS –
60
but not all – is destroyed in the sul-
50 phur converter beds. For example,
40 in this case study the three convert-
30 ers destroyed 92%, 45%, and 27% of
20 the COS fed to them. The amount of
10 COS sent to the TGTU here is small
relative to the most prevalent sul-
0
20 40 60 80 100 phur-bearing species (H2S, SO2, Sx).
% Stoichiometric air-to-acid gas ratio Despite its relatively small concen-
tration, the amount of COS sent to
Figure 4 COS sent to TGTU changes with burn strategy. Green lines represent cases the TGTU is important because it is
with no Claus reaction. Blue lines represent cases with Claus reaction proceeding to much harder to remove from the tail
equilibrium. Solid lines represent Test Run 1 with higher H2S concentration in amine acid gas – therefore it disproportionately
gas. Dashed lines represent Test Run 2 with lower H2S concentration contributes to emissions.

8 Gas 2021 www.digitalrefining.com

gas ogt.indd 3 17/03/2021 12:36

 Since burn strategy has a strong Since there is less unburned acid to provide general learnings about
influence on reheater flame tempera- gas passing through the burner, the choosing a burn strategy for AGFRs.
ture, it also has a strong influence on flame temperature is higher and this There are many practical implica-
the amount of COS generated in the has the benefit of inhibiting COS tions of choosing an operating phi-
reheater. Lower flame temperatures production. losophy that were not discussed in
favour the formation of COS. This Despite the favourability of sto- this article, including controllability,
relationship is borne out in Figure 4 ichiometric operation for process utility requirements of the unit, and
which shows that the amount of COS chemistry, mechanical constraints mechanical design of the reheaters
being sent to the TGTU increases on refractory and equipment often themselves.
when the reheater gets more acid gas limit the maximum allowable flame
than is stoichiometrically required. temperature. References
There are many other parame- 1 Anderson M, Modeling Combustion
Conclusion ters which can influence the per- Reactions in Acid Gas Fired Claus Unit
Two directional observations have formance of a particular unit. For Reheaters, 49th Annual Laurance Reid Gas
Conditioning Conference, Norman, OK, Feb 21-
been shown which demonstrate that, example, ageing of the Claus cata-
24, 1999.
from a process chemistry perspec- lyst, lower temperatures in the TR,
2 Paskall H G, Capability of the modified-Claus
tive, operating close to the stoichio- and shorter residence times without process. A final report to the Department of
metric air-to-fuel ratio is beneficial oxygen enrichment. Also, the nature Energy and Natural Resources of the province
for acid gas fired reheaters. of the Claus process makes it diffi- of Alberta, 1979.
In a typical reheater, where resi- cult or impossible to directly meas-
dence time is too short to allow the ure some important performance Clay Jones is Technical Director with Optimized
Claus reaction to come to equilib- parameters in the field. For exam- Gas Treating, Inc. He is an experienced software
rium, any unburned acid gas from ple, the exothermic transition from developer and modeller and also has field
experience as a plant engineer.
the reheater will place an addi- S2 to S8 will spontaneously occur
Harnoor Kaur is a Development Engineer
tional load on the following con- as samples cool. For these reasons,
with Optimized Gas Treating, Inc. She holds a
verter bed. When this happens in a high-quality simulation tool is one PhD in chemical engineering from Texas Tech
the last converter, it leads directly to of the best ways to study the details University.
lower overall conversion and recov- of sulphur plant operation. Elmo Nasato is President of Nasato Consulting
ery across the sulphur plant and a It should be noted that this has Ltd. He is a process engineer with over 30 years’
larger load on the TGTU. been a simplified study structured experience, specialising in sulphur recovery.

www.digitalrefining.com Gas 2021 9

gas ogt.indd 4 17/03/2021 12:36

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3/10/21 11:20
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 Stable vessel design for FLNG
Advances in floating liquefied natural gas production technology are becoming
an important factor in maintaining sustained growth of the natural gas industry
stable as the axisymmetric hull regardless of wind, waves and c
LARS ODESKAUG and SAEID MOKHATAB
Front Energy AS same time is suitable for Asian yards’ fabrication facilities. The r
shown in Figure 1.

A
s global demand for natu- technically innovative solution and
ral gas increases, the devel- potentially a commercially viable
opment of offshore floating means of exploiting remote
liquefied natural gas (FLNG) pro- offshore gas reserves.
duction technology is becoming It may also provide
an important factor in maintaining an economically pref-
sustained growth. Although off- erable option to flar-
shore LNG production has been the ing associated gas at oil
focus of research and development fields. FLNG technology
for decades, it is only in the recent may offer lower produc-
years that a few FLNG projects have tion cost, reduced time
progressed to detailed design, con- to first production, and fewer
struction and eventual operation. In environmental impacts than land
fact, some special challenges exist based alternatives. InFigure
addition, a Figure
1 Typical Cefront hull
1 Typical Cefront hull
in the design of an FLNG facility in potential advantage of a floating
the harsh offshore environment that facility is that it can be moved rel- small to midscale FLNG projects,
require special solutions. The key atively easily to an alternative
The hull is off- the liquefaction
spread moored with facility
threeisclusters
built on of
a mooring lines, o
aspect in developing a successful shore location as the original gas converted LNG carrier or on a pur-
FLNG project is the proper design has extremely
resources decline or economics favorable vessel
or pose-built motionthat characteristics
is sized more which are achiev
of the hull to provide: a seaworthy politics change. Thisrelationship as a conventional
allows the between length and LNG carrier.in combination with a b
breadth
and stable platform for production operator to save money on future When it comes to the design and
and product offloading as well as gas field developmentsstorage
or earn capacities ranging of
rev- construction froman150FLNG000facility,
m³ to 300 000 m³ (LNG
safe accommodation of the crew in enue by charging third parties to every element of a land based LNG
undergone extensive testing in the ocean test basin at Marintek
a remote, potentially hostile envi- process their gas through the FLNG facility needs to fit into a limited
ronment; and enough deck area to facility. While principally and compact
aimeditsatexceptional
verifying deckin space,
stability sea states whilst
up to significant w
accommodate the topsides process/ remote offshore gas reserves, FLNG maintaining safety and flexibility
utility units, required product stor- production technologybe canseen
alsofrom
be the example -- response
of production. amplitude operators (RA
Cargo containment
age and offloading systems, and considered for the development of andin Figure
pitch amplitudes product3 -- offloading
the Cefront systems
hull is stable compar
support facilities. nearshore gas fields with limited also need to withstand the effects
This article presents the Cefront carrier (VLCC)
infrastructure or as a combined liq- of based hull.and
the wind In summary,
waves at sea. it has
Somea number of adva
hull design, which provides a more uefaction and storage solution for of these technical challenges have
traditional ship-shaped hull, making it ideal for FLNG application
stable and economical platform for onshore gas. already been addressed, while
the offshore gas pre-treatment and Initial FLNG developments
• Low pitch wereand others such asreducing
roll motions, hull design and off-
sloshing and providing a st
liquefaction processes than conven- focused on building large scale loading technologies are still being
tional hulls. It is a further devel- facilities that can movetreatment
and process and developed
liquefaction andfacilities
enhanced.
opment of the axisymmetric hull large quantities of •LNG, typically 5
No need for turret and swivel
and is more fabrication ‘friendly’ million t/y and up, which require Cefront hull concept
and thereby less costly than earlier • High
huge capital investment. payload capacity
However, The Cefront hull design is based on
designs. The Cefront FLNG vessel the current trend is to mitigate pro- decades of experience with various
has a more efficient topsides layout
• LNG storage capacity of 225,000 m³, and additionally 45,000 m
ject risks by developing small to types of offshore vessels. The focus
than the axisymmetric units, and at mid-scale FLNG • projects, hasgirder
limiting hull
Insignificant been loads
to designanda deflections
hull that does regardless of loadi
the same time it has significantly less production capacities to 0.5-3 mil- not require a turret and is as stable
pitch and roll motions than a con- lion t/y. In large •scaleModules
FLNG pro- supported
as theby strong points
axisymmetric hullinregardless
main deck
ventional ship-shaped hull which jects, the liquefaction facilities are of wind, waves and current direc-
• Small deflections give simpler topside interface – sliding suppor
eliminates the need for expensive mounted on a barge-like structure tion, and at the same time is suitable
turret and swivel solutions. or a ship-shaped •vessel Well(depend- for Asian
known structural yards’ fabrication
arrangement based facili-
on “standard” scantlin
Floating liquefied natural gas ing on the location) with the LNG ties. The result is the Cefront hull
(FLNG) production technology is a Stiffened plate
stored in the hull• underneath. structure
In shown as for
in Figure 1. standard tankers
• Stiffener and stringer/ girder spacing as for standard tankers
www.digitalrefining.com • Not fatigue critical and hence high tensile steel
Gas 2021may
11 be used thr

• Easily scalable

gas front.indd 1 17/03/2021 12:38

 The hull is spread moored with
3 three clusters of mooring lines,
one in the bow and two aft. It has
2.5
Cefront FPSO WH=90
extremely favourable motion char-
VLCC FPSO WH=90
acteristics which are achieved by
Roll motion RAO, deg/m

2 the geometric relationship between

length and breadth in combination
1.5
with a bilge keel. Hull sizes with
storage capacities ranging from
150 000 m³ to 300 000 m³ (LNG and
1
condensate) have undergone exten-
sive testing in the ocean test basin
0.5
at Marintek, Trondheim, Norway,
verifying its exceptional stability
0
4 6 8 10 12 14 16 18 20 22 24 26 in sea states up to significant wave
Wave period, s heights of 17m. As can be seen
from the example – response ampli-
Figure 2 Roll motion RAOs tude operators (RAOs) in Figure 2
and roll and pitch amplitudes in
Figure 3 – the Cefront hull is stable
0.7 Cefront Pitch Head Sea compared with a very large crude
Cefront Pitch 135 deg carrier (VLCC) based hull. In sum-
0.7 Cefront Pitch Head Sea
Cefront Pitch 135 deg
Sign. Roll/pitch amp. / Hs (deg/m)

0.6 Cefront Roll Beam Sea

Cefront Roll 135 deg
VLCC Pitch Head Sea
0.5 VLCC Pitch 135 deg
VLCC Roll Beam Sea
0.4 VLCC Roll 135 deg

0.3

0.2

0.1

0
4.0 6.0 8.0 10.0 12.0 14.0 16.0 18.0
Peak period, Tp (s)
Sign. Roll/pitch amp. / Hs (deg/m)

0.6 Cefront Roll Beam Sea

mary, it has a number of advan-
Cefront Roll 135 deg
VLCC Pitch Head Sea tages compared with a traditional
0.5 VLCC Pitch 135 deg ship-shaped hull, making it ideal for
0.4
VLCC Roll Beam Sea
VLCC Roll 135 deg
FLNG applications:
• Low pitch and roll motions,
0.3 reducing sloshing and providing a
stable platform for the gas pretreat-
0.2 ment and liquefaction facilities
• No need for turret and swivel
0.1 • High payload capacity
• LNG storage capacity of 225 000
0
4.0 6.0 8.0 10.0 12.0 14.0 16.0 18.0 m³, and additionally 45 000 m³ con-
Peak period, Tp (s) densate or LPG
• Insignificant hull girder loads and
Figure 3 Roll and pitch amplitudes deflections regardless of loading
• Modules supported by strong
points in main deck
Ballast
• Small deflections give simpler
topside interface – sliding supports
not needed
• Well known structural arrange-
Cond.
Cond. ment based on “standard” scant-
LNG 1 LNG 2
lings/dimensions
Cofferdam • Stiffened plate structure as for
MDO standard tankers
• Stiffener and stringer/girder
spacing as for standard tankers
LNG 3 LNG 4 LNG 5
• Not fatigue critical and hence high
tensile steel may be used throughout
MDO • Easily scalable
Cofferdam

Hull design and arrangement

Cond. The hull has double sides and bot-
Cond.
tom, and offers flexibility with
LNG 6 LNG 7 respect to tank arrangement.
Typical dimensions for a 3 million
t/y FLNG unit are waterline length
of 130 m and breadth of 100 m. The
Figure 4 Plan of tank arrangement hull is flared above the waterline,

12 Gas 2021 www.digitalrefining.com

gas front.indd 2 17/03/2021 12:38

 enables normal ship-building steel to be used as the minimum steel temperature will be more
than -30°C even in an accident scenario. The insulation system is fitted directly to the vessel
hull, allowing space to be used more efficiently (see Figure 4).

Figure 5 Typical membrane CCS internal view (Courtesy of GTT) Figure 6 LNT A-Box CCS (Courtesy of LNT Marine)

Figure 4 Typical
and deck membrane
dimensions CCS internal
are typically Figure 6view
Figure
(Courtesy
shows
5 LNT
of GTT)
the LNT A-Box
A-Box CCS (Courtesy of LNT Marine)
sys- leads, chain stoppers, and winches
155 m length and 125 m breadth. tem from LNT Marine. It consists to support the mooring lines.
The hull is arranged with seven of independent IMO tanks Type Typical maximum tension in each
LNG tanks
Several with a typical
self-supported total A supported
tank containment Mooring
systemsbyarelaminated
availablecom- mooring but
in the market, linefewis 450 tonnes and the
have
capacity of 225 000 m³ and four pressed wood blocks,The withvessel
the insu- chain is
will beconsists typically
mooredof by a spreadwith
90 mm a min-system in an orie
mooring
been built. Figure
condensate/LPG 5 shows
tanks with athe LNTlation
total A-Boxattached
system to from
theLNT
innerMarine.
hull Itimum breaking load (MBL) of 900
capacity of 45 IMO
independent 000 m³. Ballast
tanks Typetanks and acting
A supported by as typically
a secondary
laminated heads
barrier
compressed into
in wood the
tonnes. prevailing
blocks, weather conditions. The vessel
with the
are arranged in double side and in accordance with International Gas
insulation attached three-point mooring system, typically with 12 mooring lines (3 clus
double bottom to thetoInternational
the inner hull Code
and acting as secondary
(IGC) 4.6. barrier in Offloading
accordance with
Convention for the Prevention of
International Gas Code (IGC) 4.6. degree spread). Offloading
Each mooring is line
side-by-side with a lower chain
has an anchor,
Pollution from Ships (MARPOL) Mooring LNG arms by FMC, SVT, or similar.
damage point. The double bottom The vessel will be element moored and by aan upper
There arechainfiveelement and
identical 16”buoyancy
arms, elements as r
inside this is void. Number of bal- spread mooring system in an ori-
The FLNG fourhave
unit will LNG, and onechain
fairleads, vapour return and winches to
stoppers
last tanks is 14. The ballast and con- entation where the bow typically (see Figure 7). The total capacity of
densate tanks extend up to the main heads into the prevailing Typicalweather
maximum thetension
system in each
is 12 mooring
000-14 line is 450 tonnes and
000 m3/h.
deck while the LNG tanks extend conditions. The vessel with ais minimum
spread breaking load (MBL) of 900 tonnes.
up to the process deck. moored with a three-point mooring Topside LNG production
The geometry of the holds in system, typically with 12 mooring The topside LNG production facili-
which the LNG containment sys- lines (three clusters of 3 x 4 in a 120 ties shown in Figure 8 comprise the
Offloading
tem will be installed is shown in degree spread). Each mooring line main gas pretreatment and lique-
Figure 4. The hold space will have has an anchor, a lower chain ele-
Offloading faction units.
is side-by-side withTheLNGrequired
arms gas pre- SVT or similar
by FMC,
a controlled atmosphere in order to ment, a polyester element and an treatment steps depend strongly on
reduce/eliminate the risk of fire and upper chain element,arms, four LNG and
and buoyancy one vapour
the level of feed return (see Figure 6). The total c
gas components.
explosion, and also to avoid con- elements as required.000 – 14 000 m3For /h. example, the low levels of sul-
densation and a humid atmosphere. The FLNG unit will have fair- phur compounds in the feed gas to

Cargo containment systems

The hull can accommodate both
membrane and self-supported inde-
pendent tank based cargo contain-
ment systems (CCS).
Membrane CCS are cryogenic lin-
ers internal to the tank. The internal
insulation system enables normal
ship-building steel to be used as the
minimum steel temperature will be
more than -30°C even in an acci-
dent scenario. The insulation system
is fitted directly to the vessel hull,
allowing space to be used more effi-
ciently (see Figure 5).
Several self-supported tank con-
tainment systems are available in
the market, but few have been built. Figure 7 Side-by-side offloading
Figure 6 Side-by-side offloading

www.digitalrefining.com Gas 2021 13

Topside LNG production

The topside LNG production facilities shown in Figure 7 comprise the main gas pretrea
gas front.indd 3 17/03/2021 12:38
and liquefaction units. The required gas pretreatment steps depend strongly on the lev
 presence of a hydrocarbon liquid
phase in the cycle.
The SMR liquefaction cycles are
UTILITY DECK
PORT SIDE:
normally appropriate options for
Offloading and LNGC small to mid-scale offshore floating
mooring systems
liquefaction systems due to their
lower equipment count, resulting
OFFLOADING
PLATFORM

UTILITY DECK
(AFT): SMR
CARGO
MACHINERY
UTILITY DECK:
FW Pumps
in a smaller footprint and lighter
MR storage and TRAIN 1 EFG/BOG/ weight, thereby lowering associ-
pumps FUEL CHEM

15 m
ated capital costs. The dual mixed
UTILITY
refrigerant (DMR) cycles, offering

COOLING WATER / SW
HEAT EXCHANGE
HHC BLOCK
135 m
SMR
TRAIN 2
REMOVAL
& FRAC.
H higher efficiency, are optimal solu-
PIG receiver, HIPPS
DE-
HYDRATION
tions for single, larger train FLNG
Inlet riser
at this side
(main deck)
ABSORBENT POWER applications. Larger trains can
(assumed) SMR LAYDOWN GEN
Prevailing wind offer economies of scale (thereby
TRAIN 3
reducing capital expenditure) and
(assumed)
INLET &
AGRU
a reduced footprint, but less oper-
Note should be made that fuel gas for the liquefactionUTILITY system
DECK: drivers and
FW Pumps
electrical
ational power and flexibil-
redundancy
165 m ity. In this case, the choices around
generation is generated UTILITY DECK: as a mixture of lean end flash gas (EFG), natural boil-off gas (BOG)
equipment will be also limited with
GT air cooling refrigeration UTILITY DECK:
from the LNG storage tanks, with supplemental fuel gas from the treatedlonger
packages SW pumping and treat.
feed gas.delivery
Excess periods, which
could potentially affect economies
BOG/EFG as well as vapour return during LNG transfer is recompressed of for re-liquefaction.
scale. 1
A single, larger train is
Figure 8 Topsides layout for Cefront vessel with LNG production capacity of 3 million t/y often preferred by owners and oper-
ators; however, the current trend is
Application
the FLNG facility of the mean Cefront thathull onlyconcept The nitrogen expander cycle to use multiple smaller trains which
CO removal is required in the acid offers lower efficiency than other have the following features:2
As a2result of attractive gas prices in the US, there are numerous LNG export projects on the
gas removal unit (AGRU). technology options, but it can be • Lower economy of scale partially
GulfAscoast;
can bea seen few are in Figurealready 8, allintheoperation, used for and small-scale
several more FLNGare produc- offset by increased
under construction competition as
or in the
process units have been configured tion because of its simplicity and more suppliers become available
planning
as singlestages.
trains except Common to all of them
the liquefac- ease isof that the export
sourcing the non-fl shipping
ammable route• to Asian markets
Operational is
flexibility (easier
tion unit which is split into three refrigerant
either around the Cape of Good Hope or through the extended Panama Canal. Both routes from onboard nitrogen start-up and improved turndown)
separate trains utilising a single generators. The absence of hydro- • Wider selection of fabrication
are timerefrigerant
mixed consuming (SMR) andcycle. expensive. Developers carbon refrigerant are therefore
inventory considering
also yards exporting LNG
fromNote
North shouldAmericabe made to that
the selection
Asian markets makesfrom the the
nitrogen
Pacific expander
coast ofpro- North•America.
ShutdownAtofleastone train does not
of the liquefaction technology for off- cess safer than the mixed refriger- stop production from other trains
one developer
shore FLNG facilities is planning will be to aggregate
influ- ant natural gas in the
(MR) processes. AsPermian
production Basin• in West maintenance
Annual Texas and can be stag-
enced by the needs of the owner. capacities move into the mid-scale gered by train
send it through existing pipelines to the Pacific coast of Mexico. About 10 – 15 km off the
Various process features including and large scale ranges, there is • Incremental capacity build-up for
the there
coast production will becapacity,
an FLNGthermal vessel, and a preference
the developer towards has MR already cycles off-takers
chosen (alignment
the Cefront hull with prevail-
efficiency, equipment count, refrig- because they are more efficient ing LNG market conditions)
aserant
the type,
basisreliability,
for the developmentspecific capital(see Figure
than nitrogen8). Theexpanderunit will haveand
cycles an export
• Phasedcapacity of 3
approach to align
investment, simplicity of operations, have lower
million t/y, and there are significant savings related to favourable gas prices in the Permian unit capital and oper- upstream development and feed gas
offshore suitability, availability, and ating costs at larger LNG capaci- supply.
(Waha
impacthub), of vesseluse motion
of the Cefront and safety hull, ties.and the shorterMR
However, distance
cycles to may Asianbe markets.
Note should be made that fuel gas
must be considered. affected by sea motions due to the for the liquefaction system drivers
and electrical power generation is
generated as a mixture of lean end
flash gas (EFG), natural boil-off gas
(BOG) from the LNG storage tanks,
with supplemental fuel gas from the
treated feed gas. Excess BOG/EFG
as well as vapour return during
LNG transfer is recompressed for
re-liquefaction.

Application of the Cefront hull

concept
As a result of attractive gas prices
in the US, there are numerous LNG
Figure 9 Gato Negro FLNG off the Pacific coast of Mexico export projects on the Gulf coast; a
Figure 12 Gato Negro FLNG off the Pacific coast of Mexico

14 Gas 2021 www.digitalrefining.com

Conclusion
The Cefront FLNG vessel is a spread moored floating unit with a unique combination of in-
hull storage capacity, high deck weight capacity and favourable motion characteristics. The
gas front.indd 4 17/03/2021 12:38
 few are already in operation, and career with Brown & Root in 1977, and has held globally as a process technology expert in the
several more are under construction senior management positions in oil service and fields of natural gas processing and LNG. He
or in the planning stages. Common technology companies since 1994, including has been actively involved in different aspects
to all of them is that the export Managing Director of Hitec Marine and CEO of several large-scale gas processing and LNG
projects for over 20 years, and has contributed
shipping route to Asian markets of TORP LNG. He has held several board
positions, has given numerous presentations to the understanding of gas processing & LNG
is either around the Cape of Good
at international energy conferences and has knowledge, practices, and technologies through
Hope or through the extended 300 technical papers and four reference books
written many articles related to innovation
Panama Canal. Both routes are in the oil and gas industry. He is a Norwegian (published by Elsevier in the US). He has
time consuming and expensive. citizen and has a degree in mechanical held technical advisory positions for leading
Developers are therefore consid- engineering from Heriot-Watt University, professional journals, societies and conferences
ering exporting LNG from North Edinburgh, Scotland. in the field of gas processing, and has received
America to the Asian markets from a number of international awards and medals
the Pacific coast of North America. Saeid Mokhatab is a senior LNG advisor of in recognition of his outstanding work in the
At least one developer is planning Front Energy AS in Norway. He is recognised natural gas industry.
to aggregate natural gas in the
Permian Basin in West Texas and
send it through existing pipelines to
the Pacific coast of Mexico. About
10-15 km off the coast there will be
an FLNG vessel, and the developer

Your
has already chosen the Cefront hull
as the basis for the development
(see Figure 9). The unit will have
an export capacity of 3 million t/y,

efficiency
and there are significant savings
related to favourable gas prices in
the Permian (Waha hub), use of the
Cefront hull, and the shorter dis-

rises
tance to Asian markets.

Conclusion
The Cefront FLNG vessel is a
spread moored floating unit with
a unique combination of in-hull
storage capacity, high deck weight
capacity, and favourable motion
characteristics. The vessel’s propri-
etary design eliminates the need
for a turret, and thereby the cost is
reduced significantly. The Cefront
design can be tailored to a wide
range of applications and is ideally
suited for FLNG as it provides a sta-
ble platform for the pretreatment
and liquefaction plants, and slosh-
ing is not an issue with the vessel’s Oil & Gas
superior motion characteristics. solutions expertise
This article is based on a presentation to
the GPA Europe Spring Conference held in
Innovative decarbonizing systems
Shell Technology Center, Amsterdam, the
Satisfying the world’s demand for more
Netherlands, May 15-17, 2019.
energy and lower carbon emissions
References requires imaginative solutions that are
1 Mokhatab S, Liquefaction Technology both sustainable and profitable. Make
Selection for Offshore FLNG Projects, PTQ, Q4, use of our expertise in resource-efficient,
107-112, 2018. low environmental impact technologies
2 Talib J H, Private Communication, Floating and services for the upstream, midstream
Technology Applications, Black & Veatch, USA, and downstream sectors.
Aug 2018.
www.man-es.com
Lars Odeskaug is the Founder and CEO of
Front Energy AS in Norway. He started his

www.digitalrefining.com 2103_19217_MAN_ES_Anzeige_SC_Power_OilGas_reSe_ENG_115x190mm_US_Webcoated.indd 1 22.02.21

Gas 2021 1510:02

gas front.indd 5 17/03/2021 12:38

 Sulfur recovery unit workers have a lot to worry
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Because we make analyzers for every part of the process—from acid-feed gas to tail gas to
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ametek.indd 1 14/09/2020 16:29
 Cleaning amine units cost effectively
Heat stable salts are dissolved or avoided by chemical products and cleaning methods
during operations and turnarounds

MARCELLO FERRARA and DOMENICO FERRARA

ITW

F
ormation of heat stable salts
(HSS) is a common issue in O
amine units and is a major fac- CO2 MEA
tor in operating costs. Accumulation HO–CH2–CH2–NH2 HN O HO–CH2–CH2–NH–CO–NH–CH2–CH2–OH
of HSS can cause more energy MEA MEA/MEA urea or MEA/Other amine urea
consumption for regeneration; O
Oxazolidone

additionally, the degraded amine H H

MEA MEA MEA
portion cannot be regenerated. This HN O OH
N
NH2 HO
N
N
NH2
Polymer
K1 K2 H
will further contribute to losses and HEEDA MEA Trimer K3

amine degradation, as well as hav- O

ing economic, environmental, and H

N
K4 CO2
operational impacts. OH
HEEDA
NH2
K-4
HO–H2C–H2C–N NH

HSS are amine salts of ionic HEIA

species such as acetate, formate, O
oxalate, acetate, thiosulphate, thio-
K5 CO2
cyanate, and chloride that are ther- H
N NH2 HN N–CH2–CH2–NH–NH–CH2–CH2–OH
HO N
mally stable and are not dissociated MEA Trimer
H K-5

to any great extent in the regener- Cyclic urea of trimer

ator. These ionic species originate

upstream of amine units as acidic Figure 1 MEA degradation induced by CO2 reaction
byproducts of other refining pro-
cesses, especially from operations bon steel in amine solvent systems; problem becomes significant when
in FCC and delayed coking units. in particular they appear to act as the total HSS concentration in the
Thiosulphate is the product of SO2 corrosion accelerators by displacing amine solution exceeds 1.5%.
breakthrough in sulphur plant the iron sulphide film. • Fouling occurs due to a mixture of
tail gas units. These acids are all Corrosion rates increase with contamination products like corro-
stronger than H2S and CO2 and they higher concentrations of all HSS sion products, salt deposits, heavy
react with amine in an acid-base species. Corrosion from HSS occurs hydrocarbons, and other solid mate-
neutralisation reaction, resulting in in hot areas of the plant where liq- rials. Areas prone to fouling are
the corresponding amine salts. uid and vapour phases are present: ones with low velocities, such as the
Amine degradation is also the reboiler, reboiler outlet line, the rich amine flash drum, that often
induced by reaction with CO2. regenerator column between the accumulate lots of fouling; as foul-
Figure 1 shows a typical degradation lean amine level, and the bottom ing accumulates, it reduces the pro-
pathway. trays. cess volume of the equipment and
HSS deposition results in the fol- HSS starts to cause obvious cor- is eventually carried over, thereby
lowing operating problems: rosion problems when the total HSS increasing the solids load of the cir-
• Irreversible consumption of level exceeds 2%: culating amine.
amine with subsequent loss of acid • Foaming due to higher concen- Amine unit fouling and corro-
loading capacity and increased lev- trations of corrosion-derived par- sion are common problems that can
els of ammonia, causing corrosion ticulates causes greater pressure adversely impact unit performance,
in the amine unit and operating drop across the column, unstable for instance:
problems in the SRU. operations (temperature changes • Fouling of the lean/rich exchanger
• Increased corrosion due to HSS inside the tower), low liquid level can ultimately lead to under-
penetrating the protective FeS layer in the absorber/regenerator causing deposit corrosion causing rich amine
on the metal surface, exposing the frequent filter switching/cleaning, leaks into the lean amine, thereby
metal to further attack. Several HSS increased liquid level in the reflux affecting sweet gas quality specifica-
anion species have been directly drum, and increased H2S or CO2 lev- tions and impairing environmental
related to increased corrosion in car- els in the treated gas. The foaming compliance.

www.digitalrefining.com Gas 2021 17

gas ITW.indd 1 17/03/2021 14:02

 • Amine contactors also foul fre- of two ways: the situation is fairly The potential locations of a slip-
quently, with the heaviest foul- typical and managed as a routine stream feeding the electrodialysis
ing occurring in the bottom of the operation; or the situation is prob- process are the same as with ion
tower. lematic and can be postponed until exchange. The electrodialysis pro-
The ‘shoe polish’ fouling mate- it can no longer be tolerated. cess also requires CO2 pretreatment,
rial is usually composed of heavy Alternatives to mechanical clean- particulate filtration, and caustic
organic compounds, polymers ing include a number of reclamation pretreatment. The contaminated
resulting from polymerisation of processes which basically clean the amine is the sent to an electrodi-
unsaturated hydrocarbons, corro- circulating amine. Three different alysis unit that uses a direct cur-
sion products, and silicon if silicon reclaiming technologies are cur- rent and a series of ion-selective
based antifoams are used to control rently used – thermal, ion exchange, membranes to separate ionic spe-
foaming. and electrodialysis. cies from the inlet solvent stream
Accurate and reliable measure- In a typical thermal reclaiming to waste streams located at the
ment of HSS concentration is essen- system, a slipstream of lean amine opposite sides of the membranes.
tial to monitor solvent degradation is taken downstream of the regener- Produced brine is sent to a waste-
and corrosion. Whenever HSS for- ator and lean amine pump and con- water treatment plant.
mation becomes out of control, it tinuously fed to the reclaiming unit. All of these reclamation tech-
can lead to an unscheduled shut- A CO2 pretreatment step occurs to nologies clean up the circulating
down and the unit must be stopped reverse the reaction between CO2 amine (normally to comply with a
because the reduced capacity is no and amine that forms amine carba- defined value of HSS in the circu-
longer acceptable. Eventually oper- mate; one potential option involves lating amine, say 1.5 wt%), but have
ating costs will increase. heating at regeneration conditions no impact on existing fouling and
Besides the concerns created to reverse the amine-CO2 reaction reduce fouling accumulation only
by HSS during a run, they create (and vaporise a small amount of to a small extent, while they do not
health and safety concern during water). The contaminated amine avoid fouling formation. The capital
a turnaround. When left inside the is then pretreated with caustic to and operating costs of reclamation
equipment, HSS will release lower reverse the reaction between acid technologies are significant; waste
explosive limit contaminants when impurities and/or degradation disposal costs and consumables also
equipment is opened, thereby products and the amine. This reac- play a role in enhancing these costs.
impairing safe entry. Because of tion creates salts of sodium and the
the heavy smell, it is also common acid impurities/degradation prod- Proactive approach
to barricade the area, which will ucts, and liberates free amine. The ITW has developed and patented
impact turnaround operations in pretreated amine is sent to the ther- technologies, together with propri-
nearby activities. Decontamination mal reclaimer where impurities are etary know-how, to dissolve HSS
will work only on the free vapour removed; the stripper overheads and hence remove them from the
space above the HSS and will not flow to a condenser and then to the equipment. A proactive approach
affect HSS deposits. Additionally, main solvent circulation loop. has also been developed for pre-
manual cleaning and/or removal of In a typical ion exchange recla- venting HSS formation.
HSS will release additional contami- mation process, a continuous slip- The application range of ITW
nants from within the deposits. stream of lean amine can be taken technologies applies from a normal
from the same location as the ther- run to a turnaround. Equipment can
Current operations mal reclaimer, or downstream of be cleaned online without the need
Mechanical cleaning is currently the lean solvent cooler before the to open it. This is particularly bene-
performed only where there is a absorber, so that the stream has ficial in severe applications such as
stringent need for it. This implies already been filtered and cooled. heat exchangers placed at elevated
that equipment is allowed to run at The ion exchange process requires locations, or in columns and vessels.
minimum acceptable performance CO2 pretreatment and caustic pre- Using ITW Online Cleaning
before cleaning. The situation arises treatment, similar to the thermal technology, an entire unit can be
from a number of peculiarities and reclaiming process. Particulate fil- cleaned in 24 hours on a feed-out/
conventions in the hydrocarbon tration is also required. The contam- feed-in basis. The advantages of
processing industry. inated amine is then passed through Online Cleaning over hydroblasting
First, the industry sees cleaning a cation exchange resin followed and mechanical cleaning include:
as a troublesome, lengthy operation by an anion exchange resin where • Reduced downtime
that leads to a production loss, so it impurities are removed. The resin • Closed loop operation, without
is to be avoided. Also, the mechani- beds are periodically regenerated the need to open the equipment
cal cleaning process involves at least with sulphuric acid and sodium • Simultaneous cleaning of multiple
20 operations, each of which has an hydroxide solutions, respectively. equipment
associated hazard. Regeneration produces large vol- • No waste generation
When the production/mainte- umes of low concentration brine • No emissions
nance department faces a cleaning which can be sent to the wastewater In particular, HSS have a heavy
situation, it normally reacts in one treatment plant. smell, which obliges workers to

18 Gas 2021 www.digitalrefining.com

gas ITW.indd 2 17/03/2021 14:02

 Others simply sell a product –
A control and shut off technique you can rely on. we offer a solution.
OHL Gutermuth

OHL Gutermuth switching- and metal seated butterfly valves are

specified and accepted internationally, as the ultimate in reactor
switching valves for Sulphur Tail Gas Clean-up Processes.
We offer an exceptionally rugged valve with a different concept. Optimize your
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low leakage rate, with a minimum pressure drop, as well as superb reliability.
Available in sizes ranging from 1” through 80” with fabricated or cast steel
body and heating jacket.
Literally dozens of plants and refineries, worldwide, using SULFREEN,
MCRC and CBA processes, among others, have OHL Gutermuth
hot gas switching valves and butterfly valves in their system
„made in Altenstadt/Germany”.
It’s good to know where to find OHL Gutermuth
perfect valve technology. Industrial Valves GmbH

Helmershäuser Strasse 9+12 · 63674 Altenstadt/Germany

Phone +49 6047.8006-0 · Fax +49 6047.8006-29 · www.ohl-gutermuth.de · og@ohl-gutermuth.de

ohl.indd 1 10/03/2017 16:12

 wear breathing apparatus for their HSS formation and removing those • Minimising fouling
removal, as well as barricade the that are already deposited main- • Minimising corrosion
surrounding area. tains peak performance in the unit. • Minimising foaming
The ITW cleaning method During a turnaround, ITW can • Minimising filter load and filter
involves the injection of an oil also provide another technology to cleaning
based chemical that transforms achieve quick and safe entry. • Minimising activated carbon
fouling into a fully reusable liquid Improved Degassing/Decontami- replacement
and thereby removes deposits from nation achieves safe entry condi- • Reducing waste generation
metal surfaces. The washing solu- tions in amine units within a few • Reducing VOC emissions
tion can be reused/reprocessed hours and uses a chemistry that • Reducing airborne pollutants
because the stabilising properties does not create emulsions, is bio- • Reducing CO2 emissions
of the chemical avoid reaggrega- degradable, and can be used in the • Improving health and safety
tion of deposits, thereby eliminating vapour phase or aqueous phase. A performance
any potential precipitation during combination of Online or Onstream A common occurrence at unit
storage and/or fouling of process Cleaning and Improved Degassing/ start-up and during maintenance
equipment. Moreover, the chemicals Decontamination will therefore turnarounds is the formation of
used in ITW’s cleaning method are reduce downtime and improve pipe scale. This forms readily when
compatible with oil and gas indus- health and safety. carbon steel is exposed to air, espe-
try processes. They: These technologies require few cially in the presence of moisture.
• do not contain any metals operating personnel, which will Any pipe scale or rust is converted
• do not contain any compounds limit the number of contractors to iron sulphide when H2S is intro-
based on P, B, S, As, Bi, Si or Pb operating in the plant and so avoid duced to the unit. Because iron sul-
• do not contain any halogens crowded operating areas during phide does not bond to the pipe it
• do not contain any compounds turnarounds and operations. will be carried away by the circulat-
that might be harmful to plant ing solution.
metallurgy Increasing revenues A further gain over mechani-
• do not contain any carcinogenic Mechanical cleaning is a lengthy cal cleaning arises in regions with
compounds and troublesome operation that severe climates. Very cold or hot
• do not contain any compounds leads to production losses, which conditions often dictate the time
that at operating dosages might counteracts the energy-saving ben- required for cleaning a process
interfere with biological waste treat- efits of cleaning. For this reason, unit. As a result, operators may
ment processes mechanical cleaning is usually post- have to accept inefficient unit per-
After online cleaning, the entire poned until the very last minute. formance until conditions improve.
unit can be immediately put back Online cleaning addresses pro- However, extreme conditions affect
on-stream without the need to duction, energy-saving, environ- only mechanical techniques such
open any equipment. ITW Online mental, safety, and reliability issues, as hydroblasting which are lengthy
Cleaning uses the current process as it can achieve equipment clean- and labour and equipment inten-
layout without modifications. ing without opening in one day, sive. ITW technology requires only
With another patented technol- making equipment quickly availa- 24 hours to clean an entire unit on a
ogy, ITW Onstream Cleaning, the ble for full production under clean feed-out/feed-in basis and only one
unit can be cleaned during the run. conditions. Additionally, avoiding or two engineers are required, with
In this case, some plant modifica- the formation of large quantities of no heavy equipment.
tions need to be implemented under solid contaminants and the reduc- Improved flexibility in solving
licence. With Onstream Cleaning, a tion of foaming that arises from operating problems is illustrated in
patented chemical is continuously their formation means a reduction the following case histories.
injected into the unit for about 24 in spending on antifoaming chemi-
hours. The results of cleaning can be cals cost and an increase in the effi- Case history 1
checked in real time since the unit is ciency of filters. A 150 000 b/d refinery was chal-
running under normal conditions. ITW Online Cleaning can be per- lenged with the need to perform
Online Cleaning and Onstream formed on a regular basis to main- a quick shutdown of its MEA unit
Cleaning effectively clean the unit tain peak performance in a unit. to make repairs to parts of the
and so remove deposited HSS. But To summarise, regular application system. The refiner chose ITW’s
HSS are also present in the circulat- of Online Cleaning achieves the fol- online cleaning and decontami-
ing amine. ITW therefore provides lowing benefits: nation approach because it does
an approach to avoiding/limiting • Keeping the unit clean and not require tube bundles to be
HSS formation. This requires con- avoiding fouling thereby avoid- removed for cleaning. The lean/
tinuous injection of another propri- ing/reducing amine reclamation/ rich heat exchangers are in a tight
etary chemical into the circulating replacement space and in an elevated position;
amine. The chemical acts on the • Keeping the unit’s performance removing the bundles for cleaning
mechanism of HSS formation. at its peak and avoiding operating/ is very difficult and creates con-
A combined approach of limiting environmental concerns cerns for maintenance and con-

20 Gas 2021 www.digitalrefining.com

gas ITW.indd 3 17/03/2021 14:02

 digitalrefining.com is the most extensive It provides a constantly growing
source of freely available information on database of technical articles,
all aspects of the refining, gas and company literature, videos, industry
petrochemical processing industries. news and events.

dr copy 20.indd 1 15/03/2021 15:10

 immediate benefits were observed:
6000 reduced steam consumption of
about 500 kg/h in the regenera-
tor reboiler, and increased delta T
5500 of about 10°C from the lean/rich
exchangers.
5000
The results are summarised in
Figures 2 and 3.
Kg/h

4500 Case history 2

A DEA unit of a delayed coker
Before was suffering severe fouling in
4000
After ITW the regenerator overhead fin fan
coolers. The fouling was a gummy
3500 material which prevented effective
1 10 19 28 37 46 55 64 73 82 91 100 109 118 127 136145154 163 172 181190 199 208 217 226 235 244 253 262
hydroblasting to be performed. The
Hours
refinery tried to remove the fouling
with high pressure water jetting but
Figure 2 Regenerator reboiler steam consumption before and after ITW Online Cleaning this operation was not effective.
The delayed coker’s overhead
gases contain olefins which are
generated by the process’s elevated
80
temperature and related cracking.
70 The olefins can polymerise and gen-
erate polymeric fouling which pro-
60 motes HSS formation.
50 ITW’s proprietary chemistry was
able to fully dissolve the gummy
40 material from the tubes by chemical
˚C

circulation. Figure 4 shows the origi-

30
nal gummy material, while Figure 5
20
Before shows the dissolved material after
After ITW
Lineare (Before)
ITW treatment.
10 Lineare (After ITW)

0
Case history 3
1 10 19 28 37 46 55 64 73 82 91 100 109 118 127 136 145 154 163 172 181 190 199 208 217 226 235 244 253 262 The MEA unit of a lube refinery
Hours had a history of HSS build-up.
In particular, fouling built up in
Figure 3 Delta T of a lean/rich exchanger before and after ITW Online Cleaning the water-oil separator and in the
Hiejector separator. The water-oil
tractor personnel. The refinery’s ITW’s online/in-situ cleaning and separator had a strong polymer
management also decided to clean decontamination was completed in deposit while the Hiejector sep-
the regenerator simultaneously less than 24 hours, with no waste arator had a typical HSS deposit
with the lean/rich exchanger to generated and significantly faster which was packing almost all of the
improve unit efficiency following than mechanical cleaning. demister. ITW applied its cleaning
restart. Upon resuming production, technologies during the turnaround.
Decontamination was performed in
the aqueous phase because of the
equipment’s low design tempera-
ture, and was completed in about 12
hours.
Figure 6 shows Hiejector demister
fouling while Figure 7 shows the
dissolved fouling.

Conclusion
Contamination costs are more
difficult to quantify than energy
costs or the costs of amine loss.
Figure 4 Gummy fouling at a DEA unit Figure 5 Gummy fouling dissolved by ITW However, if contaminant levels
processing delayed coker overhead gases treatment are allowed to build up and cause

22 Gas 2021 www.digitalrefining.com

gas ITW.indd 4 17/03/2021 14:02

 inants. ITW can provide a
holistic approach for amine
management, ranging from
prevention of HSS forma-
tion to cleaning without
opening the equipment, and
cleaning while the unit is
running.

Marcello Ferrara is the Chairman

of ITW. With 35 years’ experience in
the petroleum business, including oil
exploration and production, refining,
Figure 6 Hiejector separator demister fouling Figure 7 Hiejector separator petrochemicals, transportation,
demister fouling dissolved by ITW and energy production, he holds
operating problems, the cost can be treatment international patents for new
surprisingly high. processes and additive compositions
HSS formation reduces the effi- fouling of equipment. In addition, for environmental control and for
ciency, capacity, and reliability of an it becomes necessary to change improving petroleum/petrochemical processes,
and a PhD in industrial chemistry.
amine unit. Addressing high HSS out filters more frequently. Other
Email: mferrara@itwtechnologies.com
often involves bringing a contractor solids, like carbon fines, have the
on site to reclaim the amine solu- same bad effect on the amine unit’s Domenico Ferrara is a Process Engineer
tion, thereby incurring additional operation. with ITW. With four years’ experience in the
costs. Preventing the formation of con- oil industry and in the design of cleaning
Furthermore, iron sulphide sus- taminants in the amine system is a programmes, he holds a mechanical
pended in the amine solution con- good strategy to mitigate the oper- engineering degree from Messina University,
tributes to foaming, plugging, and ating problems posed by contam- Italy. Email: dferrara@itwtechnologies.com

www.digitalrefining.com Gas 2021 23

gas ITW.indd 5 17/03/2021 14:02

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12/03/2021 12:52
 The case for blue hydrogen
An analysis of the costs and merits of grey, blue, and green hydrogen

TARUN VAKIL and MARCO MÁRQUEZ

MATHESON, a subsidiary of Nippon Sanso Holdings Corporation

H
ydrogen is essential in petro- all the way to green (produced from ilarly to grey hydrogen, from fos-
leum refining. It enables the renewable sources). Table 1 presents sil fuels or from non-renewable
production of clean burning, a summary of the three most com- energy sources, but with a lower
low sulphur fuels, the hydrotreating mon types (colours) of hydrogen. carbon intensity. Carbon emissions
of heavy feedstocks to yield more are lowered by capturing, storing
desirable products, and the hydro- Grey, blue, and green hydrogen and/or sequestering a portion of
genation of vegetable and animal Grey hydrogen is mainly produced the total CO2 produced in the pro-
fats for the production of green fuels, by reforming of fossil fuels such as cess. Commercial processes can
among other uses. In the petrochem- natural gas, LPG, or naphtha via capture up to about 90% of the CO2
ical industry, hydrogen is the back- steam methane reforming (SMR); it produced. The cost of production
bone of reactions involved in the accounts for about 95% of the hydro- is mainly influenced by the cost of
production of multiple products of gen gas that is produced worldwide feedstock, utilities, the incremental
common use that are derived from today. The SMR process generates cost of CO2 handling (recovery, com-
syngas or from hydrogen itself. carbon dioxide (CO2) as co-product, pression, storage, transport via pipe-
Although hydrogen is a colour- a greenhouse gas that is vented to lines, sequestration), and the carbon
less and (odourless) gas, nowadays atmosphere. Grey hydrogen has one credits that often subsidise the over-
it is commonly labelled with a col- of the lowest overall (fixed and var- all cost of blue hydrogen. Carbon
our associated with the way it is iable) costs of production; it requires credits vary with geography, region,
produced and the feedstock and the less equipment and a smaller foot- politics, lobbying, and other factors.
emissions produced in its manufac- print. Nevertheless, its acceptance is Green hydrogen is produced
turing, among other considerations. coming under pressure for environ- using renewable energy. It meets the
The spectrum of colours goes from mental reasons. lowest carbon threshold when clean
black (hydrogen produced from coal) Blue hydrogen is produced sim- energy sources are used to separate

Comparison of grey, blue, and green hydrogen

Grey hydrogen Blue hydrogen Green hydrogen

Definition Hydrogen generated via Hydrogen generated from: Hydrogen generated using renewable
combustion of fossil fuel such as 1) combustion of fossil fuel or energy (solar, wind, hydroelectric),
natural gas with no recovery 2) other non-renewable energy or generated using renewable feeds
or sequestration of CO2 sources; in either case, CO2 such as biomass or digester/
emissions are recovered and landfill gas.
sequestered
Source of fuel/energy Fossil fuels Fossil fuels, other non-renewables Renewable fuels
CO2 emissions and/or recovery From hydrocarbon reforming (SMR) CO2 is recovered and sequestered, Zero emissions (if only renewable
and fuel used in the furnace; no resulting in ~60-90% fewer fuel is used in the entire process)
CO2 recovery and sequestration emissions than for grey H2. CO2
recovery will depend on storage/
sequestration capacity and logistics
H2 commercial production capacity No limitation, up to >200 000 Nm3/hr Depends on CO2 recovery/ <~5000 Nm3/hr
sequestration
Plant cost and H2 unit cost Base More expensive due to CO2 Very expensive (electrolysis);
recovery and sequestration carbon credits can offset some
equipment of the costs
Main limitations/drawbacks of H2 use Emissions Availability of a CO2 recovery/ Cost, renewable sources availability,
sequestration source 24/7 limitations, needs subsidies
and credits, maturity
Political stand Discouraged Favourable Very favourable
Incentives (vary with country/location) None Carbon credits Green and carbon credits

Table 1

www.digitalrefining.com Gas 2021 25

gas matheson copy.indd 1 17/03/2021 11:18

 Flue gas Steam

Flue gas CO2

removal unit Drum
Induced draft fan Make-up natural gas fuel gas Pressure swing absorption
purge gas fuel Boiler
feed
Boiler feed water Vent water
preheat coil Waste To
heat boiler steam drum
Steam coil H2
H2 Pressure product
Steam
swing
From
High Deaerator absorption
Mixed feed coil Steam steam drum
temperature
reformer shift Boiler feed
water pump
Steam Syngas
Flue gas CO2
Natural gas removal unit
preheater
To Condensate
Hydro- CWR
steam drum knock-out drum
desulphuriser
From Boiler feed Deaerator
deaerator water heater water heater Final cooler Make-up
de-mineralised
Natural gas feed Recycle H2 water

Figure 1 Steam reformer based hydrogen plant (with CO2 removal blocks)

hydrogen from other compounds molecule (electrolysis), and the elec- Grey and blue hydrogen production
such as water molecules. Clean tricity comes from a power plant Figure 1 shows a typical block dia-
sources of energy include wind, fed by fossil fuels (where carbon gram for a hydrogen production
solar energy, hydropower, and geo- emissions are produced), then the process using a steam reformer with
thermal. Different factors affect the hydrogen generated via this process natural gas as feed and a pressure
cost of green hydrogen. The first one is not green. swing adsorption (PSA) unit.
is the cost of the process, for exam- There have been numerous
ple electrolysis where hydrogen is successful government-backed Feed pretreatment and reforming
produced from water using renew- projects in recent years aimed at fos- section
able energy. The cost of generating tering the use of clean hydrogen. The Hydrocarbon feedstock – normally
green energy has fallen significantly International Energy Agency has natural gas – enters the plant typ-
in the past decade. Green hydrogen identified five smart policy actions ically at about 350 psig and is pre-
presents a number of challenges in that are needed.1 1. Establish long heated to about 750°F (400°C).
term of 24/7 availability of green term signals to foster investor con- Other hydrocarbons such as LPG or
energies for its production, over- fidence; 2. Stimulate commercial naphtha, either from fossil fuels or
all production cost, and the limited demand for hydrogen in multiple renewable sources, can also be used
volume that can be produced. Wind applications; 3. Help mitigate salient as a feedstock, in which case a pre-
and/or solar energy can be used to risks, such as value chain complex- reformer is required. Steam as a reac-
produce green hydrogen, which ity; 4. Promote R&D and knowledge tant for the (endothermic) reforming
can be temporarily stored during sharing; and 5. Harmonise standards reaction is added at a steam/car-
periods when there is low power and remove barriers. bon ratio of about three. This mixed
demand, or can be repurposed. The number of countries with steam/hydrocarbon feed is heated to
A more recent addition to the spec- polices that directly support invest- about 950°F (510°C) prior to entering
trum of colours is turquoise hydro- ment in hydrogen technologies is the reformer tubes. A syngas mixture
gen, produced by pyrolysis, which increasing, with a rising focus on of hydrogen, CO, CO2, unreacted
breaks down methane into hydro- existing and new applications and CH4, and steam exits the reformer’s
gen and solid carbon. However, tur- technologies, but with support for catalyst-filled tubes at about 1550°F
quoise hydrogen is likely to be no new applications such as road trans- (840°C).
more carbon-free than the blue vari- port as well. Governments have a
ety in view of emissions from the critical role to play and are work- Syngas cooling and waste heat
required process heat. ing with an increasingly strong and recovery section
There can often be a misconcep- diverse stakeholder community to The syngas is cooled in a waste heat
tion about the production of true address key challenges, including boiler to about 650°F (340°C) prior to
green hydrogen. The hydrogen pro- high costs, policy and technology entering the high temperature shift
duced is green only if the process uncertainty, value chain complexity (HTS) reactor. The HTS exit syn-
uses clean green electricity with and infrastructure requirements, reg- gas is further cooled to about 100°F
zero carbon emissions. If one needs ulations and standards, and public (38°C) in a series of heat exchang-
to supply electricity to split a water acceptance. ers prior to entering the PSA unit,

26 Gas 2021 www.digitalrefining.com

gas matheson copy.indd 2 17/03/2021 11:18

 WWW.ZWICK-ARMATUREN.DE

H2-Re
ady!

TRI-CON
SERIES FOR H2
APPLICATIONS

zwick.indd 1 17/03/2021 12:27

 tised CO2 removal systems is based
Cleaned syngas Condenser 4 Raw CO2 on scrubbing with amine solvents.
to H2 pressure
swing absorption
product Several industrial vendors offer such
systems with their own proprietary
2 Lean amine Overhead amine solvent formulations and
separator
designs. Some of the commonly used
Make-up
water amine solvents are:
WW purge • MEA – monoethanolamine (DOW)
Carbon
Reflux
pump
• DGA – diglycolamine (Econamine
filter Flue gas process by Fluor)
Absorber Stripper • DEA - diethanolamine
• DIPA - diisopropanolamine
Lean
amine • MDEA - methyldiethanolamine
Amine
cooler make-up • aMDEA - activated methyldietha-
1 nolamine (with promoter)
3 Reboiler
Syngas
feed to
absorber Amine Lean-rich CO2 recovery from high pressure
Amine circ pump exchanger Syngas and
filter or steam
syngas stream upstream of the PSA
Figure 2 is a simplified block diagram
showing the major equipment of an
Figure 2 Amine scrubbing system for CO2 removal from syngas amine treating process for CO2 recov-
ery from a high pressure (~300 psig)
which recovers 84-88% hydrogen water treatment, a deaeration sys- syngas stream. This typical system
as product at about 250 psig. The tem, and a steam drum are also pres- uses an absorber and stripper with
remainder of the syngas is collected ent to manage steam production. a steam reboiler. CO2 is absorbed
in a purge (tail) gas hold vessel at at about 104°F (40°C) into a lean
about 3-7 psig as low-Btu fuel gas. CO2 recovery amine solution. In this absorber, with
CO2 can be recovered from two either structured or random pack-
Heat supply to the reformer furnace streams (highlighted in yellow in ing, the gas rises in counter-current
and convection section Figure 1): flow against the descending flow of
PSA purge gas is the main source of 1) The high pressure syngas stream lean amine solution. This solution
fuel for the reformer furnace which upstream of the PSA (pre-PSA removes CO2 from the feed syngas;
typically equals about 60-80% of syngas) CO2-cleaned syngas exits from the top
the total furnace firing requirement 2) The reformer furnace flue gas of the absorber. The rich amine solu-
on low heating value basis. Natural stream tion from the bottom of the absorber
gas is used as make-up fuel to sup- About 60-70% of the total CO2 is heated in an economiser (lean-rich)
ply the remainder of the firing duty. emissions from a hydrogen plant exchanger against the hot lean amine
The reformer temperatures are con- are contained in the syngas stream; solution from the CO2 stripper bot-
trolled by modulating the natural almost all of this can be recovered toms. The heated rich amine solution
gas make-up fuel flow to the fur- using an amine scrubbing system. is flashed into the top of the stripper.
nace. The reformer furnace’s com- If more extensive CO2 recovery is Part of the CO2 from the rich amine
bustion flue gases exit the firebox at desired, one can recover it from solution is released directly from the
near atmospheric pressure at about the flue gas stream, but due to low top of the stripper. A stripper reboiler
1750-1850°F (950-1010°C). After heat stream pressure and low CO2 con- provides the heat required for CO2
recovery in the convection section, centration, this type of recovery is stripping. Lean amine solution from
the flue gases exit the plant at about more complex and more costly. the stripper bottom is recycled to the
300-350°F (150-175°C). Boiler feed One of the more widely prac- top of the absorber via circulation
pumps, passing through the solu-
Key streams summary: amine unit for CO2 recovery from syngas tion heat exchanger and the solution
cooler. A portion of the cooled lean
Typical syngas Syngas Cleaned CO2 Raw CO2 Raw CO2 solution is routed through a filter bed
feed to amine unit feed to syngas stripper product product in order to remove fines.
upstream of PSA absorber to H2 PSA bottoms (wet basis) (dry basis)
H2O, mol % 0.3% 0.4% 8.3% --
The CO2/H2O vapours from the
H2, mol% 75.6% 89.4% 0.5% 0.5% top of the stripper are cooled to about
N2, mol% 0.0% 0.0% 0.0% 40 ppmv 100-105°F (38-40°C) in the stripper
CO2, mol% 15.6% 0.1% 91.1% 99.4% overhead condenser. The condensate
CO, mol% 4.9% 5.8% 300 volppm 325 volppm
CH4, mol% 3.7% 4.3% 300 volppm 325 volppm
is separated from the CO2 stream in
Temperature, °F 105 115 240 to 260 100 100 the reflux vessel and routed via level
Pressure, psig 360 345 to 355 9 to 12 2 to 9 2 to 9 control and reflux pumps to the top
of the stripper to backwash entrained
Table 2 amine solvent droplets.

28 Gas 2021 www.digitalrefining.com

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 Condenser CO2
Flue gas to stack
stream
1–2% CO2
Flue gas 5 psig
Carbon
bower filter
Overhead
separator
Lean amine
Make-up recycle Amine
water make-up
WW purge
Direct Reflux
Lean amine
contact pump
Absorber pump
water cooler
Stripper
Flue gas
clean-up Lean
amine
cooler
Dirty flue Lean-rich
gas feed Water exchanger
atmospheric Steam
cooler
pressure Reboiler
Rich amine
circ pump
Lean amine
booster pump

Figure 3 Amine scrubbing unit for CO2 removal from flue gas

Low pressure steam is used in the tional challenges over that from syn- orange shaded items in Figure 3. One
stripper reboiler for safety in limit- gas, which makes the unit’s design main advantage is that the process
ing the bottom amine temperature more complex and more expensive: removes CO2 from flue gas without
below amine solvent degradation (a) Since the gas is at atmospheric disturbing the upstream pressure or
limit. The CO2 overhead is about pressure, there is a need for com- operation of the SMR process.
99% pure on a dry basis (2-9 psig) pression before processing further. Most amine systems cannot
which is sent for drying/compres- Low pressure leads to larger equip- operate in a flue gas environ-
sion. Table 2 is a key stream sum- ment size. ment, because the amine will
mary for a typical design. Syngas (b) Low CO2 concentration and low rapidly degrade in the presence
containing about 16% CO2 at 360 psig pressure leads to low partial pres- of oxygen. This is prevented by
is cleaned to a 0.1% level. Solvent sure of CO2, which requires high sol- addition of a suitable inhibitor to
rates and composition can clean the vent circulation rates. the amine solution. This inhibi-
stream down to 10-30 volppm CO2 if (c) Presence of oxygen and water tor protects the equipment against
required. The CO2 stripper bottoms leads to equipment corrosion, corrosion and permits the use of con-
temperature is dictated by the max- requiring the need to add corrosion ventional materials of construction,
imum temperature limit for amine inhibitors. mostly carbon steel.
degradation. This temperature is a (d) SOx present reacts with amines In order to avoid the formation of
function of stripper operating pres- irreversibly to produce corrosive heat stable salts in the amine solu-
sure at bottoms. Thus an optimum salts. tion, SOx, NOx (specifically NO2
operating pressure is chosen to (e) Possible presence of fly ash, par- and N2O4) and particulates must
achieve as high as possible a stripper ticulates, soot will cause foaming in be reduced to an acceptable level
pressure. The temperature limit also amine systems. upstream of the absorber.
requires only low pressure steam to (f) Presence of NOx causes corrosion These added requirements make
be used in the reboiler to limit tem- of equipment and amine degradation. the process more elaborate, espe-
peratures. Many designs use syngas (g) Flue gas pretreatment, direct cially the front end addressing flue
at 300-350°F (150-175°C) to supply contact pre-cooler/compression sys- gas contaminants (contact cooler,
part of the reboiler heat duty for tems are large and expensive. clean-up beds), corrosion due to SOx,
energy efficiency. Raw CO2 product (h) Typical energy requirement CO2 and moisture (drying pre-com-
is saturated with water vapour (4-8 for the flue gas CO2 system is about pression), low pressure requiring a
mol%), so CO2 drying will be neces- 60 000-80 000 Btu/lb-mole CO2 recov- blower, and so on. Also, large flue
sary prior to compression. ered, compared to 20 000 to 40 000 gas volumes and lower CO2 partial
Btu/lb-mole CO2 required for syn- pressure require large amine solvent
CO2 recovery from flue gas gas CO2 systems. This is due to the circulation rates and large equip-
Figure 3 is a block diagram of a typ- additional clean-up required, low ment. Materials of construction need
ical system for CO2 removal from pressure operation, and associated to address corrosion potential.
reformer furnace flue gas. The basic higher solvent circulation rates for All of these factors make low pres-
principles are the same as for recov- the flue gas system. sure flue gas CO2 recovery much
ery of CO2 from a high pressure syn- Additional equipment required more expensive compared to the
gas stream, however CO2 recovery for the flue gas system, as compared high pressure syngas option. At
from flue gas poses several addi- to the syngas system, is shown as times, for cost savings or to limit

www.digitalrefining.com Gas 2021 29

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 the amount of CO2 recovery (due to Cost and energy usage for a large SMR experience a wide range of ambient
market, storage limitation, or other based hydrogen plant – with and temperatures, so maintaining the sta-
conditions), the amine unit can be without CO2 removal from syngas bility of this single phase is impor-
employed only on part of the total tant in order to avoid two-phase
stream, with the rest of the stream Values with CO2 removal flow leading to pressure surges.
by-passing the CO2 recovery unit. Total natural gas feed utilisation, Also, contamination of CO2 can have
% increment +1.5% catastrophic consequences as it can
H2 product purity, mol% 99.99 (*)
Impact of adding a CO2 recovery H2 product pressure, psig 350 (*) cause major excursions in the prop-
unit to an existing hydrogen plant Export steam flow, % increment -33% erties and behaviour of the gas in the
If it is required to retrofit an existing Temperature, °F 750 (*) pipeline.
H2 plant with a CO2 recovery unit, Pressure, psig 650 (*) Geological sequestration involves
Power requirement, % increment +80%
the plant may need several design Gross energy usaqe (NG only), permanent storage of CO2 in geolog-
aspects investigated. % increment +1.5% ical formations below the surface of
1) For CO2 recovery from syngas: Net energy usage (w NG less steam), the earth. With easily extracted oil
• Positive impact on SMR furnace – % increment +11% already recovered, producers have
Total carbon input (as equivalent CO2),
fired duty, NG feed capacity, furnace % increment +1.5% turned to tertiary or enhanced oil
bridgewall temperatures, H2 capac- CO2 vented % reduction -60% recovery (EOR) techniques, one of
ity, H2 recovery in PSA, H2 product (*) no change, same as without CO2 recovery which is CO2 injection. Supercritical
quality CO2 acts as a solvent, dissolving the
• Negative impact on convection Table 3 residual oil, reducing the viscosity,
section coils heat transfer, steam enhancing its flow characteristics,
make, burner stability, burner flame reboiler. The hydrogen plant’s power and allowing more oil to be pumped
shape, radiant heat transfer in fur- requirement drops by 4%, however out of ageing reservoirs.
nace due to loss of CO2 in purge gas overall power consumption increases Saline aquifers are also considered
(emissivity loss), lower heat transfer by 80% due to the additional require- for CO2 sequestration. Because of the
coefficients in furnace on flue gas ments of the CO2 recovery and com- sub-surface temperature profile of
side due to lower flows (less CO2), pression areas. The gross efficiency terrestrial storage sites, CO2 stored in
reliability of plant as more prone to of natural gas usage becomes worse these reservoirs is buoyant; a portion
upsets by the same ratio as the total increase of the injected CO2 can escape if the
2) For CO2 recovery from flue gas: in natural gas usage. The net energy reservoir is not appropriately sealed.
• Minimal impact on main SMR usage increases by 11% due to lower Injecting CO2 into deep sea sediments
process export steam rates. (few hundred feet in depth) is said
• Positive impact is it will free up to provide permanent geologic stor-
some capacity for induced draft fan CO2 drying, compression, storage, age even with large geomechanical
due to less flow, higher pressure flue and transport via pipeline perturbations. At the high pressures
gas (actually, the plant may not need The recovered CO2 stream is satu- and low temperatures common in
one any more) rated with water; it must be dried deep sea sediments, CO2 resides in
• Negative impact on induced draft before compression to about 2500- the liquid phase and can be denser
fan operation and reliability, and 2700 psig for transport via long pipe- than the overlying pore fluid, caus-
convection section coil heat transfer line networks in the supercritical ing the injected CO2 to be gravita-
state (dense phase). Glycol washing tionally stable. Additionally, CO2
Relative impact/cost of CO2 removal is employed for CO2 drying, typi- hydrate formation will impede the
from high pressure syngas stream cally after third or fifth compression flow of liquid CO2 and serve as a sec-
Table 3 shows the impact of add- stages. Liquid phase CO2 transport ond cap on the system. If challenges
ing a CO2 recovery system to a large has a smaller volume but larger pres- can be overcome, the potential for
hydrogen plant (≈100 mmscfd). It sure drop and possible plug issues global CO2 storage capacity in coast-
compares a ‘with’ and ‘without’ due to dry ice formation. Gas phase lines is enormous, capable of storing
CO2 recovery section with the same transport results in large volumes thousands of years of CO2 emissions
hydrogen production. The total natu- and large pipe sizes. Supercritical at current rates. CO2 still needs to be
ral gas required is about 1.5% higher or dense phase transport results in transported to any sequestration site.
for the 60% CO2 removal case; this significantly lower pressure drop There are several developing
is because lower flow of PSA tail in pipes compared to the gas or liq- applications for CO2 such as for
gas (CO2 removed) results in less uid phase. For pipeline transport, cement/cure concrete by direct injec-
heat recoverable from the convec- CO2 should be compressed suffi- tion, CO2 to chemicals, polymers, liq-
tion section, and consequently lower ciently to ensure that single-phase uid fuels, nanotubes, and graphene.
combustion air preheat tempera- flow is maintained throughout the Table 4 shows a typical specifica-
tures. The furnace excess air needs pipeline. The typical operating pres- tion for pipeline transportation. CO2
to be higher as well to improve flue sure is 1100-3000 psig. Above 1100 recovered by amine systems can
gas flows. The export steam flow psig, CO2 exists as a single dense easily meet this specification (purity
drops by 33% due to internal energy phase over a wide range of temper- ~99%). The maximum limit on water
requirements for the CO2 stripper atures. A transmission pipeline can content is to prevent equipment cor-

30 Gas 2021 www.digitalrefining.com

gas matheson copy.indd 5 17/03/2021 11:18

 rosion that occurs in the presence ing into account all the possible To produce blue hydrogen, a CO2
of CO2, oxygen, H2S, and others. To synergies between them, allowing recovery system was added to the
limit corrosion, the specified H2S optimisation of the overall process conventional SMR design (described
maximum limit is 200 volppm and with minimum overall emissions.2 in detail in the previous section).
specified oxygen maximum limit is In a recent commercial study, Subsequently, the CO2 had to be
10 volppm. Matheson assessed the impact of sequestered. The use of CO2 in the
using grey versus blue hydrogen food and beverage industry does not
Case study: use of grey vs blue for a third party producing green qualify for blue hydrogen because
hydrogen in a green fuel production fuels from hydrotreated vegetable the CO2 re-enters the atmosphere.
facility oil (HVO), primarily HVO diesel. For the CO2 recovery, two options
In order to mitigate environmental The hydrogen plant was designed were considered:
emissions, refiners are increasingly for multiple feedstocks, including
required by government mandate to natural gas and (byproduct) HVO 1) CO2 recovery from syngas
include a fraction of renewable fuel naphtha. The grey hydrogen plant High purity CO2 product is recov-
in their pool; this primarily applies considered a conventional (mul- ered from syngas downstream of the
to gasoline and diesel. Furthermore, ti-feed) SMR with steam byproduct. reforming/shift conversion, before
green fuels, also referred to as sec-
ond generation renewable fuels, can
represent highly lucrative business
since low cost renewable fats, oils,
and greases (organic materials) can
be monetised as renewable (green)
diesel, jet, and naphtha.
One key step in the process of
making green fuels is the hydro-
genation of organic materials at ele-
vated temperature and pressure in
a catalytic reactor — comparable
to refinery hydroprocessing. The
hydrotreating step in green fuels
production requires high-severity
conditions to cope with the nature
of the raw material. Depending on
the feedstock and technology, over-
all consumption of hydrogen can
be comparable to, or even higher
than, petroleum based hydrocrack-
ing. Consequently, the overall green
effect of the process can be dimin-
ished by the emissions of the hydro-
gen plant. It is therefore essential
that the green fuel production unit
and the hydrogen plant (collectively
the green facility) are designed tak-

Standard industry specification for

pipeline CO2

SPEC: Interstate pipeline transport of CO2 -

enhanced oil recovery (EOR)
CO2 95% min. by volume
Pressure >2160 psig (compress to
2700 psig)
Water <30 lb water vapour /Mcf
CO2, NO free water
H2S 10 to 200 volppm
O2 <10 ppmv
Temperature <120°F
N2 <4 mol%
Hydrocarbons <5 mol%
Glycol <0.3 gal glycol/Mcf CO2

Table 4

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gas matheson copy.indd 6 18/03/2021 15:40

 CO2 recovery (none), and emissions.
Tail gas (fuel to SMR)
Nat gas
trim fuel
Because of the additional complexity
and equipment, the addition of a CO2
HVO
Naphtha
section to produce blue hydrogen
Nat gas feed
Steam Methane H2
Green adds about 30-50% to the capex and
HVO Naphtha
reformer
PSA fuel
unit
a comparable incremental amount to
feed HVO operation, maintenance, and chem-
(from Green fuel unit)
Steam Diesel
icals. The amount of CO2 that can be
CO2 CO2
CO2 gas for recovered from the syngas is limited
Flue gas removal compression
to stack
Steam recovery/ to the carbon in the feed, and is about
sequestration
export
64-68%, depending on the feedstock.
The flue gas recovery option is more
Figure 4 Integrated blue hydrogen-green fuel unit with CO2 recovery from syngas expensive but allows recovery of up
to 90% in both cases. The variable
cost of hydrogen (excluding any car-
Nat gas Tail gas (fuel to SMR) bon credits which vary by geogra-
trim fuel
phy and other factors) also increases.
HVO Main components contributing to
Nat gas feed Green
Naphtha
the variable cost of grey hydrogen
H2
Steam Methane
reformer
PSA fuel are the feedstock (usually ~85-90%,
unit
HVO Naphtha
feed HVO including feed, fuel, and the credit
(from Green fuel unit)
Steam Diesel for steam byproduct) with the bal-
Flue gas
CO2 CO2 ance being power (~5-10%), water,
CO2 gas for
Flue gas removal compression
recovery/ and other utilities (~2-5%). In the case
to stack
sequestration of blue hydrogen, the power cost is
greater due to the incremental energy
Figure 5 Integrated blue hydrogen-green fuel unit with CO2 recovery from flue gas requirements for CO2 recovery and
compression. Compared to grey
hydrogen, the power requirements
Comparative summary for grey and blue hydrogen production
in the case of CO2 from syngas is
Grey H2 Blue H2 almost double, and almost four times
CO2 from syngas CO2 from flue gas for the case of CO2 from flue gas.
H2 plant capex cost Base +32% + 52% Incremental steam is also required
O&M, chemicals cost Base +25% +54%
Natural gas feed
in the CO2 recovery section. To sat-
% of CO2 recovered 0 64% 90% isfy the heat requirements associated
Difference in variable cost of H2 (*) Base +25% +53% with the amine system in CO2 recov-
Fossil fuel (NG) emissions, MTPD Base -202 -267 ery, the hydrogen plant goes from
HVO naphtha feed
% of CO2 recovered 0 68% 90%
being a net steam exporter in the case
Difference in variable cost of H2 (*) Base +12% +32% of grey hydrogen to a reduced steam
Fossil fuel (NG) emissions, MTPD Base -258 -326 exporter or even a net importer of
steam in the case of blue hydrogen.
(*) Cost bases: Natural gas: 3.4 US$/mmbtu (HHV); HVO Naphtha: 7.9 US$/mmbtu (HHV);
Power: 0.11 US$/kwh. No carbon credits were assumed. The amount of CO2 emissions attrib-
uted to natural gas is reduced signifi-
Table 5 cantly, 200-260 t/d in the case of CO2
recovered from syngas and 270-325
the PSA (see Figure 4). The residual and fuel to the hydrogen plant ends t/d in the case of CO2 recovered from
syngas (essentially hydrogen, CO, up in reformer furnace flue gas from flue gas.
unreacted methane, and nitrogen) is which it can be captured. Calculation of net emissions can
separated in the PSA into high purity Table 5 is a comparative summary also be expressed as kg CO2/kg
hydrogen (main product) and purge for grey and blue hydrogen produc- hydrogen produced, taking into
gas (tail gas) which is used as the tion in a mid-size hydrogen plant account the CO2 emissions associ-
main fuel in the reformer furnace. (25-35 kNm3/h) with the two CO2 ated with manufacture and use of
recovery options and for two differ- the feed, fuel, and utilities (power,
2) CO2 recovery from the furnace flue ent feedstocks. CO2 is recovered and demineralisation, cooling and waste
gas compressed to the customer’s battery waters, instrument air, nitrogen,
In this more complex, more capi- limit, who would later handle the and other utilities). Each component
tal intensive arrangement, CO2 is sequestration/storage step (excluded has an associated emission factor
recovered from the flue gas prior from the evaluation). For the pur- expressed as gmCO2eq/MJ which
to the stack (see Figure 5). If no CO2 poses of this comparison, production adds to the overall emissions, with
is recovered from syngas, all carbon of grey hydrogen was considered feed, fuel, and power being the main
contained in the hydrocarbon feed as the base case; in terms of cost, contributors. The emission factors

32 Gas 2021 www.digitalrefining.com

gas matheson copy.indd 7 18/03/2021 15:40

 varyring.
greatly by geography,
In total, four hot tapssource of production,
were installed onand the
other factors. 3
The net emissions in the
pressure shell, two in the side downcomers case of HVO of naph-
Tray 8
tha compared with natural gas are much lower, since the
and two below
feedsump.
the normal liquid level in the
emissions (main overall contributor) are zero in the
column
WHAT CAN ENSURE MY
case ofThe
and 2018.
renewable
blue hydrogen,
HVO were
bypass lines naphtha.
put When comparing
into operation
The steam cracker unit operating rate emis-
although there are lower overall
in grey
mid-
could
PLANT‘S LONG-TERM
sions,
be the incremental
increased to 97% compression power requirement
ethylene production capacity. EFFICIENCY?
diminishes the overall net effect.
On-specification overhead and bottom products were
The presentwhile
produced analysis deliberately
the bypass was indid not consider
operation. the
The debu-
costtaniser
of anywas carbon credits associated with the
opened in a later turnaround and severe recovery
and/or sequesteringfouling
polymerisation of CO2was so the reader
found can bottom
on the appreciate
tray
the active
impactareasof these subsidies which vary by
and in their downcomers (see Figure 7).geography,
local/regional policies, political appetite, environmental
restrictions,
Conclusion and other factors. Neither was the incremental
costInand logistics for CO2 sequestration/
summary, thorough analysis of field storage consid-
data and tray
ered.hydraulics
There are together
multiple with
initiatives aimed at CO
gamma scanning 2were key capture
or reuse,
factorsasfor mentioned
a time- andin the previous section.
cost-efficient Carbon
troubleshooting.
credits and economics of sequestration are
Close collaboration between the plant owner, Tracerco essential to
bridge the gap in cost between grey and blue
scan experts, and engineering company personnel hydrogen.
made the troubleshooting discussed here a success.
Conclusions
Hydrogen
References is nowadays labelled with a colour associated
with1 its
Perryproduction
R H, Green D W, process, feedstock,
Perry’s Chemical andHandbook,
Engineers’ emissions,New
among
York,other considerations.
McGraw-Hill, 2008. Grey, blue, and green hydro-
gens2 are theHmost
Kister common
Z, What known
caused tower types; each
malfunctions one
in the lastwith its
50 years,
pros and cons. Blue hydrogen (fossil fuel base with CO2
Trans. Inst. Chem. Eng., 2003, Vol. 81, 5-26.
sequestered) is viewed
3 Pless L, Simon as a bridge
Xu, Distillation between
tower flooding low complex
– more cost, high
than
you think, Chemical Engineering, Jun 2002.
emissions grey hydrogen and high cost, limited scale, zero

EXPERIENCE!
4 Lockett M J, Distillation Tray Fundamentals, Cambridge University
emissions green hydrogen. Compared to grey hydrogen,
Press, Cambridge, 1986.
blue hydrogen requires a higher capital and variable cost
for CO
Lowell
2
recovery
Pless wasandthe sequestration.
Business Development Manager – Distillation The know-how of more than 60 years empowers Böhmer
The emissions
Applications withfrom incremental
Tracerco, use of Texas,
located in Pasadena, energy (pri-
and is now
to build Ball Valves that help customers to realize their
projects efficiently & successfully for the long term.
marily power) for
a consultant required for compression,
the company. separation,
He has been applying and
radioisotope
sequestration CO2 must
techniques inofprocess also be accounted
troubleshooting for. Carbon
for over 30 years, originally
credits,
with availability
Tru-Tec Services of (acquired
sequestration sites,inand
by Tracerco 2006)processing
and started 1/8 TO OIL, GAS, STEAM, CHEMICALS UP TO
56 INCH & SPECIAL APPLICATIONS 800 BAR
coststheare essential
tower scanningfor the deployment
service of blueEurope
for Tru-Tec in Western hydrogen.
and the
Green hydrogen must use renewable sources to produce
Middle East. He holds a BS degree in chemical engineering from the
true zero emissions in the production process; this repre-
University of Texas at Austin, is a registered Professional Engineer
in the State of Texas, participates on the Design and Practices
sents challenges in terms of cost and scale of production
committee for Fractionation Research (FRI), and is a member of the
among other factors.
American Institute of Chemical Engineers.
Governments have a critical role to play in addressing
key challenges. Blue and green hydrogen can be profitable
André Perschmann is an equipment process design expert with Linde
with carbon credits.
Engineering for eight years. He designs all types of columns and
References
separators for petrochemical, natural gas, hydrogen, and synthesis gas
1 Theplants.
FutureHeof isHydrogen, report
also involved in prepared
root causebyanalysis,
the IEAtroubleshooting,
for the G20, Japan and
(Jun 2019).
revamp activities. He holds a diploma degree in bioprocess engineering
2 Marquez
from theM,Technical
Bumgarner B, Optimum
University use of H2 in theGermany.
of Braunschweig, production of drop-
in green fuels, 2020 AFPM Summit, www.hydrocarbonprocessing.com/
conference-news/2020/08/2020-afpm-summit-optimum-use-of-h2-in-
David Bruder is a process and operation expert for petrochemical
the-production-of-drop-in-green-fuels
plants with Linde Engineering, planning, simulating, and optimising
3 Methodology for the calculation of GHG emissions from Biofuels and
all relevant processes within the Linde petrochemical portfolio with
Bioliquids, Doc. 2BS-PRO-03, www.2bsvs.org/documents/public/2BSvs_
a focus on steam cracker separation technology. He is involved in
PRO_03_Methodologie_de_Calcul_des_GES__F__v1.pdf
brownfield/revamp projects such as capacity increase, optimisation,
Tarunlife
Vakil is Director
cycle, energy, or oftroubleshooting
Hydrogen Technology
existingforplants,
NipponandSanso
in theHolding
analysis
Corporation’s
of processUS andsubsidiary
operationMatheson. He has more than
performance/optimisation 45 years
of running of
plants.
experience in engineering and industrial gases and holds a BS degree in
chemical engineering
Thomas Walter fromheads
The Indian
the Institute of Technology,
Equipment ProcessBombay,
Designand&
a MSComputational
degree in chemical engineering
Mechanics from Pennsylvania
department State University.
of Linde Engineering where
Email: tvakil@mathesongas.com
his group is responsible for the process design of static equipment for
Marco Márquez is Global Director of Hydrogen Business Development
petrochemical, natural gas, air separation, and hydrogen/synthesis gas
– Refining with Matheson. He has more than 30 years of combined
plants. He holds a master’s degree in process engineering from the
experience in the oil industry and with industrial gas companies and
holdsTechnical
MSc andUniversity, Dresden,engineering
PhD in chemical Germany. from North Carolina State
University. Email: mamarquez@mathesongas.com www.boehmer.de

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gas matheson copy.indd 8 17/03/2021 11:18

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 www.gastechevent.com

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gastech.indd 1 11/12/2020 12:47
 Monitoring gas emissions
Analysis of gases supports cleaner air initiatives in hydrocarbon processing

MARK CALVERT and SANGWON PARK

Servomex

I
ncreasingly, plant operators are the fuel to produce unwanted emis- More recently, tunable diode laser
becoming highly sensitive to their sions such as oxides of nitrogen (TDL) technology has been intro-
contribution towards greenhouse (NOx) and sulphur (SOx). Accurate duced for this application, pro-
gas emissions. This awareness has gas analysis of oxygen and combus- viding even faster measurement,
been driven by ever more strin- tibles such as carbon monoxide (CO) particularly for carbon monoxide. It
gent environmental regulations has provided a way to better balance also gives an average measurement
and international action to reduce the air-to-fuel ratio and control the across the measurement path, rather
the impact on climate, such as the combustion reaction. than the result at a single point.
2016 Paris Agreement. To support Controlling combustion produces However, since TDL sensing is
their efforts to reduce emissions and a number of benefits, particularly highly specific to the gas being meas-
operate in an ecologically respon- for plants looking to meet environ- ured, separate analysers are required
sible way, many plants are looking mental standards requirements. Fuel for O2 and CO.
towards gas analysis systems to pro- consumption is reduced, resulting Servomex has the Servotough
vide the solution. in fewer emissions, a reduction in Laser 3 Plus Combustion TDL
A combination of solutions for NOx, SOxgas
Monitoring and CO, and a decrease in analyser for this application, and this
emissions
combustion efficiency, gas clean-up, the greenhouse
Analysis gas carbon
of gases supports initiatives incan
cleaner airdioxide be confiprocessing
hydrocarbon gured to measure either
and emissions monitoring sup- (CO ).
Servomex
2 author TBA O 2
or CO. It can also be configured
ports plants in their goals, not only Zirconia based sensing technology for a joint measurement of CO and
ensuring that air remains clean, but is long established as a solution for CH4, providing a rapid-response
Increasingly, plant operators are becoming highly sensitive to their contribution towards
optimising processes for reduced O2 monitoring in combustion, and measurement for safety in natural
greenhouse gas emissions. This awareness has been driven by ever-more-stringent
fuel consumption and higher yields delivers reliable, accurate results gas fired heaters and boilers.
in hydrocarbon processing (see environmental
with a fastregulations,
responseandtointernational
changing action toAdditionally,
reduce the impactiton isclimate, such as the
important to
Figure 1). conditions. It has the advantage that note that gas analysis is used in
2016 Paris Agreement. To support their efforts to reduce emissions and operate in an
a combustibles
ecologically sensor
responsible way,can
manybe added
plants many
are looking applications
towards gas analysistosystems
support to greater
provide
Effective combustion control easily,
the and at modest cost, to pro- process efficiency. The more efficient
solution.
Combustion is an integral part of vide
A an all-in-one
combination combustion
of solutions for combustioncon- thegasprocess
efficiency, clean-up, reaction
and emissionsis, monitoring
the fewer
many hydrocarbon processing appli- trol solution, such as in Servomex’s harmful emissions are likely
supports plants in their goals, not only ensuring that air remains clean, but optimising processes to be
cations, with no realistic alternatives Servotough FluegasExact 2700 com- generated, so this also
for reduced fuel consumption and higher yields in hydrocarbon processing (see Figure 1).
plays its part
available to create the extremely bustion analyser. in cleaner air.
high temperatures required. The
combustion reaction mixes fuel with
oxygen (from air) in a fired heater,
delivering heat energy that can be
transferred elsewhere in the pro-
cess. This reaction typically requires
a significant amount of fuel, creates
potential safety hazards, and gener-
ates harmful emissions.
The most efficient reaction is one
where the ratio between air and fuel
is optimised. Prior to the develop-
ment of gas analyser technology,
fired heaters were typically run in
high excess air conditions. This was
inefficient and increased the level of
fuel consumption, but avoided the
creation of unsafe conditions that
could lead to an explosion.
An excess of oxygen (O2) also com- Effectivemonitoring
Figure 11 Effective
Figure monitoringof of gases
gases reduces
reduces emissions
emissions andand operating
operating costs
costs in
in hydrocarbon
bines with nitrogen and sulphur in hydrocarbon processing
processing

www.digitalrefining.com Gas 2021 35

Gas servomex.indd 1 17/03/2021 12:41

 Ammonia can be monitored by
extractive sampling, but this is diffi-
cult, since the sample must be kept
Economiser bypass
Flue gas above 290°C to prevent the forma-
from boiler
tion of ammonium bisulphate and
Urea or ammonia
sulphuric acid.
injection point Inlet NOx concentration, fuel com-
Economiser
position, and catalyst performance
can also affect the measurement,
while infrared based extractive sys-
tems may also be impacted by sig-
Catalyst nal interferences from gases formed
layers x3 by the process, and by high levels of
Multiple nozzles spraying
dust.
A more effective solution is a TDL
Servotough
Laser 3 Plus
analyser – such as the Servotough
Laser 3 Plus Environmental installed
TDL
directly into the process ducts (see
Figure 2). This provides a signal that
is averaged across the duct, for a
more accurate NH3 reading despite
uneven flow conditions.

Figure 2 Laser 3 Plus TDL analyser in ammonia slip applications Flue gas desulphurisation
The purpose of a flue gas desulphur-
For example, one of the largest air SpectraExact 2500 is suited to off-gas isation (FGD) system is to remove
emissions sources in a refinery is the CO and CO2 measurements. sulphur compounds (SOx, princi-
fluid catalytic cracking (FCC) unit, pally SO2) from exhaust gases. It is
which requires multiple gas meas- Cleaning process gases a process usually utilised by fossil
urements across the process. The second phase of Servomex’s fuelled power plants and operators
In a typical FCC unit, a process clean air strategy is to tackle gas in other SOx-emitting processes.
control oxygen measurement is cleaning, that is the removal of A method commonly applied
required in the regenerator off-gas, harmful substances from process sees the flue gas sprayed with a wet
where low O2 will cause incomplete gases that might otherwise be emit- slurry of lime, which reacts with
combustion (and, therefore, removal) ted by the plant. SOx and scrubs up to 95% of the SO2
of the catalyst coke and excess O2 can Typical applications within this content from the gas. Gas analys-
reduce catalyst life. area include ammonia slip treatment ers measure the SO2 content after
Measurement of CO and CO2 in and flue gas desulphurisation. treatment to ensure any remaining
the same off-gas helps calculate cat- sulphur compounds fall within regu-
alyst coke formation, enabling cat- Ammonia slip latory limits.
alyst regeneration efficiency to be To suppress the harmful emissions Since gases containing SOx can
determined. Excess O2 and CO levels of NOx from combustion, ammo- be corrosive, and treatment tem-
require monitoring in the regener- nia or urea is used, either in a SCR peratures are usually kept high to
ator flue gas, while ammonia slip is or selective non-catalytic reduc- prevent moisture content from dam-
measured at the selective catalytic tion (SNCR) process. Both methods aging equipment, gas analysis faces
reduction (SCR) outlet to control the require accurate ammonia dosing a challenge. Non-contact, photomet-
NOx removal process. to reduce NOx levels. If insufficient ric sensing technology provides the
Each point of this process ben- NH3 is used, then NOx emissions most effective and accurate measure-
efits from the application of an are not sufficiently suppressed, ment for SO2 in this application.
appropriate technology: the off-gas while too much NH3 can lead to the Servomex’s Servopro 4900
measurements for O2 and NH3 slip eventual formation of ammonium Multigas uses infrared gas filter cor-
benefit from the use of TDL open- bisulphate. relation (GFx) technology to meas-
path measurements which reduce Ammonium bisulphate is a white ure SO2 in this application. This
issues with catalyst particulates powder that can plug the catalyst in sensing method allows real-time
experienced by in-situ or simple SCR processes, causing equipment measurements accurate to very low
extractive systems. damage and reducing the value of levels, without interference from
Close-coupled extractive systems, the fly ash by-product, so it is vital background gases.
such as the FluegasExact 2700, are that plants manage NOx removal This technology can also support
reliable and cost-effective for making processes efficiently, controlling the sulphur recovery units (SRU) which
O2 and combustibles (COe) flue gas level of ammonia slip to 2-3 ppm recover sulphur from streams con-
measurements, while the Servotough ammonia. taining H2S.

36 Gas 2021 www.digitalrefining.com

Gas servomex.indd 2 17/03/2021 12:41

 Carbon capture and storage (CCS) EU, for example, have both commit- Hydrogen gas (H2) burns much
Capturing and storing CO2 instead ted to reducing carbon emissions to more cleanly than CH4, as it does
of releasing it to the atmosphere not net zero by 2050. not contain carbon, so cannot form
only results in a cleaner environ- Monitoring flue gas emissions not CO2 as a byproduct of combustion.
ment, but also allows the CO2 to be only helps determine the process effi- The purity of the hydrogen affects
used in other processes. It encom- ciency and protect the environment, its quality as a fuel, and this is where
passes elements of both gas cleaning it also ensures – and demonstrates gas analysis again plays a role.
and emissions monitoring, and so – that plant operators are complying Depending on the manufacturing
falls within both phases of the clean with the necessary regulations. method, the most common contam-
air strategy. The three greenhouse gases men- inants will be O2, CO, and CO2. All
There are three methods for CCS. tioned above are not the only emis- three of these can be monitored by
Post-combustion CCS takes place sions that must be measured in the MultiExact 4200, Servomex’s
when CO2 is removed from the order to achieve a clean air strategy multi-component analyser, using a
flue gas after fossil fuels have been and meet regulatory requirements. mixture of paramagnetic, infrared,
burned. Oxyfuel CCS produces a flue NOx and SOx are also key pollut- and gas filter correlation technology.
gas consisting almost entirely of CO2 ants, as is CO. Whatever cleaner energy sources
and steam by reacting the fuel source A continuous emissions monitor- emerge now and in the future, it is
with almost pure O2. This means flue ing system (CEMS) is required to a certainty that gas analysis technol-
gas can be stored/sequestered with- measure all the necessary compo- ogy will have an important part in
out significant pretreatment. Both nents of the flue gas to ensure com- the process.
these methods can be retrofitted to pliance. The solution employed must
existing plants or used in new ones. be capable of offering the highest Conclusion
A third method, pre-combustion sensitivity and accuracy when deal- Gas analysis plays an essential role
CCS, is performed prior to burning ing with multiple measurements for in cleaner plant and refinery oper-
the fuel, and converts the fuel into a pollutants and greenhouse gases. ations, whether it is used to ensure
mixture of hydrogen and CO2. This Multi-component gas analysers, more efficient processes, to support
is difficult to retrofit and so is better such as the 4900 Multigas, are suited the safe removal of pollutants, or to
suited to newly built facilities. to this application and, depending monitor the remaining emissions
Once the CO2 is captured, by on the process, can either deliver all that are output to the atmosphere.
whichever method is used, it is then the necessary measurements in one It also supports emerging trends
compressed into a liquid and trans- device or form a key part of an inte- in the industry including greater
ported for storage. grated, comprehensive CEMS. For process optimisation, the move to
Industrial level CCS is a process example, a single 4900 Multigas can cleaner fuels, and achieving higher
that is likely to grow in years to monitor four gases simultaneously, product yields.
come, particularly as countries look measuring from a choice of O2, CO2, To achieve this wide range of
to meet Paris Agreement targets for CO, SO2, NO, CH4, and N2O, so mul- goals, an equally wide range of
carbon reduction, and requires accu- tiple analysers can easily cover the sensing technologies is needed. By
rate gas analysis. pollutants of interest. offering a diverse selection of tech-
The Servotough SpectraExact 2500 Any gas analysis system must nologies, and the expertise to back
photometric analyser is suited to also meet MCERTS and QAL1 certi- them up, Servomex is able to ensure
this application. Capable of single- fications to comply with regulatory the best-fit and most cost-effective
or multi-component gas monitor- criteria. solution for each application.
ing in corrosive, toxic or flammable Service support is another essential
streams, it uses infrared and gas fil- Gas analysis to support cleaner consideration – forging a service con-
ter correlation technologies to meas- energy sources tract that maintains gas analysis sys-
ure CO2 at percentage and parts per Many plants are also moving to tems at peak performance ensures
million levels. cleaner energy sources, such as the refinery or plant continues to
This means it can measure the flue hydrogen, while plants that produce operate in the cleanest way possible.
gas to ensure most CO2 has been hydrogen are ramping up output to Each of the phases outlined here
removed, and is also capable of meet increased demand. contributes towards a cleaner air
assessing the purity of the removed Blue hydrogen is produced using strategy. However, by combining all
CO2 prior to it going to storage. fossil fuel sources, such as natural three, plants and refineries can fully
gas, through steam methane reform- address the impact of their opera-
Monitoring flue gas emissions ing (SMR), and can be supported by tions on the wider environment, and
The reduction of carbon emissions in carbon capture processes to counter play their part in creating a world
particular has dominated the agenda the CO2 produced. with cleaner air.
for many countries in recent years, Green hydrogen is created from
with legislation reducing the accept- non-fossil fuel sources, such as Mark Calvert is Global Head of Service with
able amounts of greenhouse gases water, using processes like electrol- Servomex.
– CO2, CH4, and nitrous oxide (N2O) ysis, fuelled by renewable sources SangWon Park is Business Unit Director IP & E
– that can be emitted. The UK and like wind. with Servomex.

www.digitalrefining.com Gas 2021 37

Gas servomex.indd 3 17/03/2021 12:41

 Getting the most out of syngas
Optimise production and effectively remove CO2 from syngas with the right
separation equipment

CLAUDIA VON SCALA and NATALIA MOLCHANOVA

Sulzer Chemtech

C
arbon dioxide (CO2) removal
is one of the most common
activities that producers and
users of synthetic gas (syngas) need
to perform to obtain suitable feed
for downstream processes. By uti-
lising advanced separation column
internals, including the latest col-
umn packings, businesses can max-
imise efficiency, throughput, and
CO2 capture while also supporting
environmental goals.
Syngas is a key product and ingre-
dient for a wide range of applica-
tions within the manufacturing and
processing sectors, including petro-
chemical and ammonia production.
However, the levels of CO2 in this
mixture may need to be adjusted and
businesses often process this gas in
order to reduce CO2 concentrations.
In a number of industrial appli-
cations, it is more advantageous to Figure 1 Shell Schoepentoeter
adjust the ratio of hydrogen versus
carbon in syngas via shift reactions inlets release the gas from a singu- feed, performing a first stage separa-
to utilise pure hydrogen in their lar opening and hardly separate tion of liquid from the vapour, and
processes. In some other cases, CO2 the vapour and liquid phases using achieving an even vapour distribu-
is removed from syngas to increase gravitational forces only. Businesses tion across the vessel’s cross section.
efficiency and chemical conversion can improve their separation perfor-
in downstream activities as well as mance by adopting a radial system, Succeeding in CO2 removal
to prevent catalyst poisoning or cor- such as a tangential vapour horn New and existing CO2 removal units
rosion. Carbon capture can also help or a Shell Schoepentoeter, which for syngas should also leverage the
to reduce the environmental impact divides the feed into a series of dis- latest generation of packing solu-
of different manufacturing activities. crete horizontal streams, using a tions, such as Sulzer’s fourth-gen-
number of vanes (see Figure 1). This eration NeXRing random packing.
How to feed the system can be installed in new facilities or Replacing conventional second-gen-
In all cases, businesses need to retrofitted in existing units. eration random packings with the
select advanced and robust solu- Thanks to these innovative latest components can increase
tions that can minimise both the designs, it is possible to dissipate the column capacity by 25-35% while
concentration of CO2 in syngas and kinetic energy and momentum of maintaining, or increasing, separa-
energy consumption while maxim- the stream, reducing the likelihood tion efficiency and product quality.
ising throughput and yield. When it of liquid entrainment. In addition, Upgrades in the design are one of
comes to separation, column pack- the vapour horn can provide the the main reasons for these substan-
ing and internals play a key role in feed with centrifugal acceleration tial improvements. These changes
the overall efficiency of the process. that promotes the liquid-vapour have allowed manufacturers to
One of the first elements to look separation process, even under high increase the uniformity of their bed
at is how the syngas feed enters the loads. The Shell Schoepentoeter can distribution as well as the system’s
separation unit. Conventional feed also decrease the momentum of the wettability, strength, and durabil-

38 Gas 2021 www.digitalrefining.com

gas sulzer.indd 1 17/03/2021 12:47

 ity. Furthermore, newer generation also possible to decrease the over- lising state-of-the-art separation
random packing can maximise the all pressure drop by 10% in the equipment, companies can maxim-
interfacial area between gas and liq- absorber and by 50% in the regen- ise their throughput and process
uid, as well as liquid flow rate. erator. Furthermore, the manufac- efficiency, optimising the volume
turer was able to increase separation of CO2 removed as well as syngas
Case study: CO2 removal performance by reducing the con- recovery rates. A separation spe-
A large chemical company, special- centration of CO2 at the outlet by cialist, such as Sulzer, can help to
ised in the production of nitrogen 30%. As a result, an intensification identify the best technology for an
based chemicals and mineral fertiliz- of the ammonia synthesis process intended application. Sulzer’s teams
ers, wanted to increase the capacity was achieved, increasing the overall have been supporting industries
of its CO2 removal unit to boost the output. in a variety of sectors with effec-
production of technical ammonia In addition, considerable reduc- tive column internals and packings.
from 1500 tons/day (1361 tonnes/ tions in pressure drop within the These have been key to boosting
day) to 1900 tons/day (1724 tonnes regenerator allowed the plant to CO2 removal strategies, ultimately
per day). After assessing the system, reduce the temperature at the bot- enhancing competitiveness in
Sulzer suggested the replacement of tom of the column by 4°C. This led increasingly challenging markets.
the second-generation random pack- to a more energy efficient process Claudia von Scala has worked for Sulzer
ing in the absorber and regenerator and greatly reduced the risk of ther- Chemtech in various positions, mostly related
with NeXRing as well as upgrad- mal degradation of the solvent. As a to packings. She holds a master’s degree in
ing to a Shell Schoepentoeter feed result, the plant can now reuse most chemical engineering from the University of
inlet device. In addition, the existing of this solvent, as it is reintroduced Strathclyde, Glasgow, UK, and a PhD from the
sieve trays were replaced with fixed into the CO2 removal loop and then Paul Scherrer Institute/chemical engineering
valve trays, which would allow the used in subsequent separation pro- department of ETH Zürich, Switzerland.
manufacturer to increase column cesses, optimising the raw material Natalia Molchanova is Process Development
capacity, while also increasing the consumption. Manager with Sulzer Chemtech Russia,
promoting innovative processes for special
separation efficiency and lowering
applications and providing technical support
the pressure drop per theoretical Conclusion and training for the simulation of refinery and
stage. The effective removal of CO2 C&P applications and processes. She holds a
These upgrades helped to boost from syngas is required to enable master’s degree in chemical technology and
the capacity of the plant’s CO2 a number of downstream activ- engineering studies from the University of
removal system by 27%. It was ities for manufacturers. By uti- Saint Petersburg, Russia.
ERTC 2018

managing
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www.digitalrefining.com Gas 2021 39

n
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In this example, the trick was essentially
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