Carbon Dioxide removal processes for Enhanced Oil Recovery

UNIVERSITY OF SURREY
Faculty of Engineering & Physical Sciences
Comparison of Carbon Dioxide Removal
Processes for Enhanced Oil Recovery
Mehdi Abdelkader Aissani
A dissertation submitted in partial fulfillment of the requirements
for the Degree of Master of Science in
Process Systems Engineering
September 2015
© Mehdi A Aissani 2015

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I. Declaration of Originality
I hereby declare that the dissertation entitled ‘Comparison of CO2 removal processes
for Enhanced Oil Recovery’ for the partial fulfilment of the degree of MSc in Process
Systems Engineering , has been composed by myself and has not been presented or
accepted in any previous application for a degree. The work, of which this is a record,
has been carried out by myself unless otherwise stated and where the work is mine,
it reflects personal views and values. All quotations have been distinguished by
quotation marks and all sources of information have been acknowledged by means
of references including those of the internet.
Student’s name: Mehdi Abdelkader Aissani Date: September 2nd
2015

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II. Acknowledgements
To my Supervisor Dr Antonis Kokossis goes my sincere gratitude, his advice and
guidance were very useful for meeting the standards required in this paper.
I would to like take this opportunity to acknowledge and thank a very special person,
Mr Amin Aissani who is no other than my father, thank you for your support and
believing in me.
In addition, I am very thankful to the University of Surrey and the Department of
Chemical and Process Engineering. It was a memorable year for me where I have
seen my academic skills improve day by day.
Finally, there are no words that can describe enough or convey my gratitude to my
family; their love and constant presence has been my biggest motivation for this
project.

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III. Abstract
Efforts to commercialise high carbon dioxide content natural gas have traditionally
been unsuccessful due to high processing costs. However, increased demand for
natural gas can make development of marginal, high carbon dioxide content gas
fields an attractive proposition despite the high carbon dioxide disposal costs, usually
to underground storage, so as to avoid emissions to atmosphere.
CO2 removal processes can be broadly classified as solvent based, adsorption,
cryogenic or physical separation. The advantages and disadvantages of these
processes will be discussed in this thesis. This paper addresses and compares the
different processes available for CO2 removal from natural gas and its re-injection for
EOR. The comparison will be focused on parameters which affect process selection
the most such as, project execution, economic, health and safety impact and
maturity. A performance index will be generated with scores attributed to each
technology for their performance in different category labelled as Key parameter.
The results showed that chemical solvent processes are the most suitable for CO2
capture and injection for enhanced oil recovery. They are the most widely used, most
versatile and cost effective technologies for all natural gas sweetening applications.
Amine processes are among the safest and most reliable, based on a considerable
industrial experience. Membrane technology showed the second highest score. This
confirms that technology evolution of CO2 removal by membranes could be profitable
if it could be implemented into large scale projects, because it has a very low
operating costs and minimum Health and Safety Impact. Cryogenic would be
promising technology for the future if Ryan Holme fractionation column is used in
combination with the Controlled Freeze ZoneTM
fractionation column.

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IV. Table of Contents
1. Introduction ....................................................................................................... 8
1.1 Background.....................................................................................................................................8
1.1.1 CO2 removal from natural gas ........................................................................................................... 9
1.1.2 Enhanced Oil Recovery.......................................................................................................................10
1.1.3 EOR methods..........................................................................................................................................10
1.1.4 Carbon dioxide enhanced oil recovery (CO2-EOR) .................................................................11
1.2 Project objective.........................................................................................................................12
2. Literature review.............................................................................................. 14
2.1 Effects of CO2 and greenhouse gases on climate change..............................................14
2.2 Carbon capture and storage (CCS).......................................................................................15
2.3 Technologies available for CO2 capture.............................................................................16
2.3.1 Chemical Solvents.................................................................................................................................17
2.3.2 Membranes..............................................................................................................................................20
2.3.3 Physical Solvents...................................................................................................................................22
2.3.4 Cryogenics (ExxonMobil and Ryan Holmes).............................................................................23
2.3.5 Mixed Physical-Chemical Solvents ................................................................................................26
2.3.6 Physical Adsorption.............................................................................................................................27
2.4 CO2 storage in depleted oil and gas reservoirs ...............................................................29
2.5 Cost of CO2 sequestration........................................................................................................29
2.6 Oil recovery by CO2 injection.................................................................................................30
2.7 Oil recovery mechanisms by CO2 injection.......................................................................32
2.8 Ongoing CO2 projects................................................................................................................32
3. Methodology .................................................................................................... 35
3.1 Aim and objective ......................................................................................................................35
3.2 Evaluation methodology .........................................................................................................35
4. Evaluation of each option............................................................................... 38
4.1 Project execution .......................................................................................................................38
4.2 CO2 composition and percent removal in feed gas ........................................................39
4.3 Economic.......................................................................................................................................42
4.4 Ease of equipment design .......................................................................................................43
4.5 Maturity.........................................................................................................................................44
4.6 Health and safety impact.........................................................................................................46
4.7 Energy requirements................................................................................................................47
4.8 Market conditions (materials costs, consumables costs)............................................49
4.9 Technology evolution with time...........................................................................................50
4.10 Experience with combined CO2 removal and injection................................................50
4.10.1 SACROC project................................................................................................................................51
4.10.2 SLEIPNER project............................................................................................................................52
4.10.3 The WEYBURN project..................................................................................................................53
5. Conclusions..................................................................................................... 54
6. Future work and recommendations............................................................... 56
7. References....................................................................................................... 57
8. Appendices ...................................................................................................... 61
8.1 Process selection evaluation table ......................................................................................61

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V. List of Figures
Figure 1 | CO2 capture from an LNG plant (CO2CRC, 2015)...................................... 9
Figure 2 | Changes in global mean surface temperatures since 1856 (Parties, 1997)
.......................................................................................................................... 14
Figure 3 | Carbon Capture and Storage concept (Verdon, 2015) ............................. 16
Figure 4 | PFD for a typical MDEA unit..................................................................... 19
Figure 5 | PFD of a typical single stage membrane unit ........................................... 21
Figure 6 | PFD of a typical two-stage membrane unit............................................... 21
Figure 7 | PFD of a typical Selexol unit..................................................................... 23
Figure 8 | CFZTM
Principles of Operation (Charles, 2008) ........................................ 24
Figure 9 | PFD of a typical Sulfinol unit..................................................................... 27
Figure 10 | PFD of a typical physical adsorption unit................................................ 28
Figure 11 | Carbon dioxide enhanced oil recovery concept (Mogollong, 2015) ........ 31
Figure 12 | Location of sites where activities relevant to CO2 Storage are or under
way (ADCO, 2010) ............................................................................................ 33
Figure 13 | Gas sweetening selection chart (Project, Azrafil, 2007).......................... 40
Figure 14 | Gas sweetening technology selection chart (Project, Azrafil, 2007) ....... 40
Figure 15 | Effects of CO2 removal ........................................................................... 48
Figure 16 | U.S. Oil Production from CO2-EOR Projects by Year (O&G, 2006) ....... 52
Figure 17 | The Sleipner field with CO2 injection (Statoil) ......................................... 53
VI. List of Tables
Table 1 |Production, reserves and residual oil in place; U.S. onshore, excluding
Alaska (Geffen, 1973)........................................................................................ 10
Table 2 | EOR processes categories (Lake, 1989) ................................................... 11
Table 3 | Current and planned carbon capture and storage projects (Metz, et al.,
2005) ................................................................................................................. 34
Table 4 | Comparison of Amine and Membrane CO2 removal systems (Echt, 2008) 45
Table 5 | Large Carbon Dioxide Miscible Projects in the U.S. (O&G, 2006) ............. 51
Table 6 | Evaluation table ......................................................................................... 62

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VII. Abbreviations
AGRU
BTEX
CCS
CFZ
DEA
DOW
DIPA
ECBM
EGR
EOR
FEED
FLNG
FPSO
GHG
GSGI
HAZOP
HCPV
IPCC
kPa
LNG
LTS
MBD
MDEA
MEA
MBD
MMBD
MMSCF
NGCC
NGL
SRU
TBD
TRRC
TGU
UOP
UN
WAG
Acid Gas Removal Unit
Benzene Toluene Ethyl benzene Xylene
Carbon Capture and Storage
The Controlled Freeze Zone (CFZ)
Diethaloamine
Chemical company name
Di-isopropanol amine
Enhanced Coal Bed Methane
Enhanced Gas Recovery
Enhanced Oil Recovery
Front End Engineering Design
Floating LNG
Floating Production Storage and Offloading
Green House Gases
Gravity-Stable Gas Injection
Hazard and Operability
Hydrocarbon pore volume
Inter-governmental Panel on Climate Chance
Kilo Pascal
Liquefied Natural Gas
Low Temperature Separation
Million barrels per day
Methyldiethanolamine
Monoethanolamine
Thousand barrels per day
Millions of barrels per day
Million Tons Per Annum
Natural Gas Combined Cycles
Natural Gas Liquids
Sulphate Reduction Unit
To be Determined
Texas Rail Road Commission
Tail Gas Unit
Universal Oil Products
United Nations
Water Alternating Gas

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1. Introduction
One of the key concerns the world is facing today is the threat of climate change and
global warming. This has been linked by scientists to greenhouse gases emissions.
Carbon dioxide (CO2) plays a major role in these concerns. Although aspects of the
science remain the subject of expert debates, there is nowadays a broad consensus
that climate change is occurring and this is reflected in both international and national
initiatives. Most industrialised countries, including UK, have signed up to international
conventions and programmes, in particular the UN Framework Convention on
Climate Change 1992 and the Kyoto Protocol 1997.
In much of the world, the commercial production of natural gas is threatened by
marginal economics. This is particularly true with raw gas containing a high
concentration of contaminants that are expensive to remove. Even countries with
significant gas reserves are turning to importing liquefied natural gas (LNG) with its
attendant geopolitical concerns over certainty of supply and cost. Alternatively they
consider increasing their use of high carbon (but low cost) fossil fuels for power
generation. Maximising the use of indigenous natural gas has to be a priority to
ensure security of supply at reasonable in order to offset the use of high carbon
producing fossil fuels that contribute to climate change.
The LNG industry has had need to reduce costs and enhance revenue even though
their inlet gases have become more difficult to process. CO2 removal processes from
new prospects are becoming a more critical factor in overall optimized design of LNG
facilities (Stone & Jones, 2008). The Injection of CO2 as part of Enhanced Oil
Recovery (EOR) increases the production of oil by approximately 5-15% in addition
to what is typically achievable using classic recovery methods (Tzimas et al., 2005),
while easing the storage of CO2 in the oil reservoir in the long-term.
1.1 Background
Natural gas represents a major resource of energy on earth. In the early stages of
the exploitation of fossil fuel, associated gases used to be flared. Nowadays natural
gas has become a major source of energy as a domestic and industrial fuel (Veroba

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& Stewart, 2003). The removal of CO2 from natural gas is now an established
technology that has been applied on an industrial scale since the 1980s. The end-
use specification, whether for pipeline transport into a supply grid or for liquefaction
and onward transport as LNG, requires the CO2 concentration to be reduced to 2-3
mol%. Various technologies have been applied, including physical and chemical
solvents, membranes, and cryogenic separation. The preferred technology, in any
specific application, depends on the feedstock and required output compositions
(Rackley, 2010).
1.1.1 CO2 removal from natural gas
Natural gas is mixture of gases with about 90% of it being methane, with ethane and
propane occupying the majority of the remaining 10%. It also has some inorganic
gases such as, oxygen, nitrogen, sulphur compounds and carbon dioxide.
Natural gas that contains low volumes of these inorganic gases (impurities) is usually
used as fuel without the need of treating or gas sweetening. However natural gas
with higher volumes of impurities cannot be combusted efficiently and safely. One
example would be the natural gas produced at the Sleipner Field in the North Sea.
This gas contains high levels (approximately 9%) of carbon dioxide, however in order
to meet client specifications, the gas need to be treated to a percentage of 2.5 %.
There are many processes that can be used to remove CO2 from natural gas, for this
reason the process to be used has to be selected meticulously. Figure 1 shows an
example of CO2 removal in an LNG plant.
Figure 1 | CO2 capture from an LNG plant (CO2CRC, 2015)

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The different processes have advantages and disadvantages which make the
process selection for carbon capture a critical part for a project (Sheimekit & Mukhtar,
2012).
1.1.2 Enhanced Oil Recovery
EOR can be defined as the methods used for oil recovery from petroleum reservoirs
which cannot be recovered by primary and secondary methods. EOR is used to
compensate the decrease in the mobility of the oil through the process of drilling. It
primarily does this through the use of injecting fluids in the drilling process. EOR
processes can result in 30-60% in oil recovery using primary or secondary methods
(Sino, 2013).
Much of the interest in EOR centres on the amount of oil it is potentially recoverable.
Table 1 shows this target oil accounts for 278 billion barrels in the United States
alone. This represents nearly 70% of the 401 billion barrels of the original oil in place.
If EOR could recover only 10% of this, it could more than double the proven domestic
reserves (Lake, 1989).
Table 1 | Production, reserves and residual oil in place; U.S. onshore, excluding Alaska (Geffen, 1973)
Category Billions of barrels Percent of original oil in
place
Produced 101 25.2
Proved reserves 22 5.5
EOR target 278 69.3
Total 401 100.0
1.1.3 EOR methods
With a few minor exceptions, all EOR processes fall distinctly into one of the
following four categories: thermal, gas, chemical, Microbial flooding gas miscible
recovery and other. Table 2 summarises the main processes within each category
(Lake, 1989). The definition of each of the processes is categorised by their injected
fluid properties. In this context, gas enhanced oil recovery includes carbon dioxide
miscible/immiscible hydrocarbon processes.

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Table | 2 EOR processes categories (Lake, 1989)
Thermal EOR
processes
Gas EOR
processes
Chemical EOR
processes
Other EOR
processes
Steam flooding Hydrocarbon
miscible/immiscible
Micellar-polymer Carbonated water
flood
Cyclic
stimulation
CO2 miscible Polymer Microbial
In-situ
combustion
CO2 immiscible Caustic/alkaline Electromagnetic
heating
Hot water
flooding
Flue gas (miscible
and immiscible)
Alkaline/surfactant
Steam-assisted
gravity drainage
Gravity drainage
Some idea of the popularity of the individual processes follows from the biennial
survey of U.S. EOR activity compiled by the Oil and Gas Journal. These numbers
tend to under-estimate actual activity since they are based on voluntary surveys. The
surveys do not distinguish between pilot and commercial processes. In past until
recently, it is believed that thermal methods, particularly steam drive and soak,
occupied the largest share of EOR projects and have experienced growth since
1971. This density reflects the long-standing commercial success of steam flooding
(Lake, 1989). Recently Gas EOR processes have experienced a significant growth.
Major research efforts have been put in these processes, especially in the Arab
counties and in the U.S.A.
1.1.4 Carbon dioxide enhanced oil recovery (CO2-EOR)
CO2 injection into an oil reservoir, which is usually near the end of its economic
lifetime is a promising technique to enhance oil recovery (CO2-EOR), is it increasingly
applied in many promising commercial projects worldwide. CO2 is sequestered
through the injection well into immobile oil and empty pores and oil water and CO2
are produced at the production well. Oil and water are separated as they are denser.
The CO2 goes through compression and is then recycled into the injection well. CO2-
EOR projects have the objective to maximise oil recovery using minimum injection
quantity of CO2, this brings a contradiction as it is desired to maximise CO2
sequestration to reduce greenhouse gases emissions.

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EOR via carbon dioxide injection is particularly appropriate for oil fields with low
recovery rates which are located close to the source of carbon dioxide (to minimise
carbon transportation costs) and where carbon dioxide emissions to atmosphere
incur a significant cost penalty. Joint work between ADNOC and Masdar to develop
large scale carbon capture and storage (CCS) is targeting 70% oil recovery (Oil &
Gas Journal, 2012). Studies in Kuwait have been promising. It is expected that
carbon dioxide injection will dominate EOR in the Middle East, maybe as soon as
2020.
About 84 commercial CO2-EOR operations are ongoing in the USA, Canada,
Hungary, Turkey and Trinidad. 200,000 barrels (bbl.) of oil per day is produced, a
small but significant fraction (0.3%) of the 67.2 million bbl. per day total of world-wide
oil production in 2004 (Herzog & Golomb, 2004).
1.2 Project objective
The principal objective of this Thesis is the evaluation of the best gas treatment
technologies to be used to remove acid gas from a feed gas for enhanced oil
recovery (EOR).This study will review the available CO2 removal processes and
discuss the factors that can influence the choice of the best process. . The important
key parameters in the selection of an acid-gas process methodology are:
 Project Execution
 CO2 Composition in feed Gas
 Economic
 Ease of Equipment Design
 Maturity
 Health and Safety impact
 Energy costs
 Market conditions (materials cost, consumables costs)
 Technology evolution with time
 Company experience with a certain technology

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This report also compiles the up to date technologies related projects to enhanced oil
recovery in depleted and mature oil and gas reservoirs.
CO2 injection system, as part of the EOR system, is a technique used to extract the
maximum oil amount. This system is performed through injecting inert gases like
carbon dioxide to the oil wells. The main objective of the CO2 injection is to stimulate
the oil droplets that are inside the oil reservoir rock. As explained above CO2 is the
ideal solvent for oil. It can move oil from the reservoir much more efficiently than
water.

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2. Literature review
2.1 Effects of CO2 and greenhouse gases on climate change
Tyndall has done experiments on the absorption spectrum of carbon dioxide in the
infrared spectrum region. The laboratory results from his work have shown that CO2
is a highly toxic greenhouse gas which affects the habitable temperature range on
earth (Pearson & Palmer, 2000). CO2 is a major greenhouse gas and the most
apparent consequence of CO2 emission into the atmosphere is global warming.
However, CO2 has also impact on plants and animals as it is physiologically active.
For this reason, CO2 is very important to ecological systems and its acid form
critically affects the chemistry of ocean water.
The average global temperatures have increased by roughly 0.6 ºC over the 20th
century (Levy, et al., 2004) as shown in Figure 2.The majority of the observed
warming over the last decades is linked to human activities. Moreover, precise
analysis, studies and climate models referenced by the IPCC are predicting that
global temperatures may increase by between 1.4 and 5.8 ºC between 1990 and
2100 (Parties, 1997).
Figure 2 | Changes in global mean surface temperatures since 1856 (Parties, 1997)

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Among the various GHGs, the most prevalent of them is CO2. For instance, CO2
accounted for 82 % of total U.S. GHG emissions from 1991 to 2000 (Parties, 1997)
(Houghton, et al., 2001).
While the climate scientist is focused on the effects of CO2 on the environment and
eventually global warming, the engineer is more focused on the development of a
sustainable energy infrastructure in order to eliminate impacts on the environment
that result from the emissions of CO2 to the atmosphere. On a more general note, the
energy engineer evaluates the impact of generating power on the environment.
2.2 Carbon capture and storage (CCS)
The creation of a CO2 waste stream, for example from a gas processing LNG plant is
unavoidable. The process is considered as a large scale stationary point source and
CO2 capture is essential from its waste streams to meet certain specifications as
explained in chapter 1.1.1.
The idea of CCS is very simple: for each ton of carbon produced another ton of
carbon has to be safely and permanently stored. The geological storage of CO2 that
is captured from important industrial sources consists of the deep injection below the
ground, CO2 is then trapped in porous rocks including oil reservoirs, the main
objective is to reduce CO2 emissions and keep this gas isolated from the
atmosphere. The whole industrial process chain involves CO2 capture, transport and
storage, commonly referred to as CCS. Figure 3 shows the concept of CCS.
The injection of CO2 into the sub-surface is routine in the oil and gas industry. These
techniques are used to enhance oil and gas production. There are various oil and
gas technologies and techniques that can be used to conduct CO2 capture and
storage. These technologies are available in the market but are costly in general,
they approximately contribute to around 70-80% of the total cost of a full CCS system
(Leung & Caramanna, 2014). However, there is still much to learn, particularly in
improving predictive performance of storage sites (Micheal, et al., 2009).

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Figure 3 | Carbon Capture and Storage concept (Verdon, 2015)
Various treating processes are available for bulk capture of CO2 but preference is
often given to proven technologies. However, considering the significant capital
investment involved on gas processing projects, a comprehensive technology
selection study encompassing newer and conventional technologies is needed.
Geological storage of CO2 captured from such projects have the potential to stabilise
and reduce global emissions to the required (50% plus) by 2050, it has also the
potential for increased oil recovery.
2.3 Technologies available for CO2 capture
Acid gases removal (hydrogen, carbon dioxide and sulphur) from natural gas is
defined as gas sweetening processes. Natural gas that contains high volumes of
carbon dioxide (CO2) needs to be treated in order to:
 Prevent corrosion of pipelines and gas processing equipment.

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 Prevent solidification of CO2 during cryogenic processing.
 Increase the heating value of the gas
On the other hand, hydrogen sulfide (H2S) present in the natural gas needs to be
removed in order to:
 Prevent corrosion of pipelines and gas processing equipment.
 Avoid safety concerns due to H2S toxicity.
 Prevent formation of carbonyl sulfide (COS) if CO2 is present and if some types of
molecular sieves are used for dehydration.
There are many methods that may be employed to remove acid components from
gas streams. The available methods can be categorized as those depending on
chemical reaction, absorption, adsorption or permeation through a membrane.
The following is a general classification of main removal methods for acid gases such
as (CO2):
 Chemical Solvents .
 Membranes.
 Physical Solvents.
 Cryogenics (ExxonMobil CFZ and Ryan Holmes)
 Mixed Physical-Chemical Solvents.
 Physical Adsorption.
2.3.1 Chemical Solvents
Processes that utilise chemical solvents have been widely used in LNG plants for
many years. Potassium carbonate-based solvents can efficiently remove CO2 and
H2S but cannot reach the low levels of CO2clean-up needed in gas processing and
LNG industry. Consequently, these processes must be combined with other
processes for complete removal.
Chemical processes that use amine solvents can do the required removal in one-
step. Amines, such as, MEA and MDEA are used in many gas processing plants and

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provide good service. These amines however, require larger regeneration heat
requirements and are more corrosive than other processes.
The popularity of MDEA has been increasing; MDEA is usually applied with
proprietary activators to facilitate acid gas pickup (Meisser & Ulrich, 1983). Its
advantages are that it is less corrosive and has lower regeneration heat duties than
other amine. With the incorporation of a semi-lean MDEA recycle stream, which is
only flash regenerated, heat duties can be lowered further. This type of processing
takes advantage of the physical absorption capacity of MDEA. A common
characteristic of chemical-solvent based processes is the low amount of co-absorbed
hydrocarbons. This distinctive feature not only gives lower hydrocarbon losses, but
also allows easier integration of the heavy-hydrocarbon removal steps necessary for
LNG processing, Figure 4 shows a typical MDEA unit. Although both CO2 and H2S
must be removed to ppm levels in the product LNG, a selective H2S removal process
using hindered amines may also be used. This process could selectively remove H2S
to enrich the feed gas stream to a Claus sulfur plant. (Royan, 1992). This process
can be applied to the original feed stream or the acid gas after its removal by another
process.
The acid gas reaches the contactor, where the amine reacts with CO2 and H2S. The
lean amine enters the top of the contactor. Rich loading (i.e. moles of acid gas/mol of
amines in the aqueous solution leaving the contactor) is adjusted to minimize amine
circulation while considering corrosion limitations.
The rich amine stream pressure is let down, and it releases hydrocarbons absorbed
in the contactor. They are separated in an amine flash drum. The lean/rich amine
heat exchanger allows recovering heat from the lean amine.
The amine still strips CO2 and H2S off the amine solution by means of stripping
vapors generated in the reboiler (mainly steam). Rich amine enters the still column in
the top section. The still operates at approximately 1.9 bara and 125ºC at its bottoms.
The acid gas is cooled in the amine still reflux condenser.

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Figure 4 | PFD for a typical MDEA unit
The amine still strips CO2 and H2S off the amine solution by means of stripping
vapours generated in the reboiler (mainly steam). Rich amine enters the still column
in the top section. The still operates at approximately 1.9 bara and 125ºC at its
bottoms. The acid gas is cooled in the amine still reflux condenser.
Condenser outlet stream flows to the amine still reflux accumulator from where amine
still reflux pumps withdraw condensed water and send it to the top of the still column.
The lean amine is transferred from the still bottoms to the amine surge drum. Booster
pumps are placed in line to overcome the static and friction head needed to pass
through lean/rich amine exchanger and the lean amine cooler. This cooler takes the
lean amine solution to the desired temperature. Final pumping of lean amine solution
takes place in main amine pumps.

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2.3.2 Membranes
In a membrane system, components from a multi-component mixture pass through a
dense or fine film, from a region of high pressure to one of low pressure, based on
the solubility and diffusivity of the chemical species in the inlet gas.
Separation lies in the difference of rates at which the gases diffuse across the film.
“Fast” gases collect in the permeate stream and “slow” gases remain in the non-
permeate stream (residue stream). Water vapor, CO2 and H2S are highly permeable
gases and are easily separated from bulky hydrocarbon molecules.
Separation efficiency is affected by differential partial pressure across the membrane,
temperature, pressure ratio, separation factor and gas composition. Membranes are
not selective enough to avoid high hydrocarbon losses. Alternatively, higher capital
and energy expenses for recompression and recycle can be used to avoid those
losses. Another serious shortcoming is that membranes alone cannot produce LNG-
quality gas; consequently, additional processing must be done. The capital
expenditure and energy efficiency of membrane systems are very sensitive to the
acid gas level of the product gas. If this process is chosen, the designer must
carefully choose the amount of acid gas removal done in the membrane system and
the amount done in the downstream process. We have not identified any situation
where we think membranes might be economic in the processing for an LNG plant.
The membranes consist of a thin polymer film on top of a thin porous substrate.
These films are joined together in cylindrical membrane elements. Membrane
elements are inserted into a tube, and multiple tubes are then mounted on skids in
either a horizontal or vertical orientation.
Good feed conditioning is essential for membranes. Membrane damage is directly
attributable to lack of efficiency in inlet separation. Contaminants that have potential
to damage membrane elements are liquid water, some lubricating oils, propylene
carbonate and poly-nuclear aromatic hydrocarbons (present in well treating
chemicals or corrosion inhibitors). Items that cause a decline in membrane
performance include glycol, methanol, methanol-based solvents, amine-based
solvents, aromatics (i.e. toluene, xylene, etc.), water and condensed hydrocarbon
liquids. Hydrocarbon condensation can cause severe damage to some membrane
materials.

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The pre-treatment equipment is usually dependent and varies with the feed gas
conditions and compositions. The inlet of the pre-treatment equipment depends
mainly on the gas composition. A conventional pre-treatment operation includes:
coalescing filter, adsorbent (activated carbon) guard bed, dust filter and heater.
Enhanced pre-treatment could include an LTS Unit (mechanical refrigeration), a
Joule-Thompson Expansion Unit or a Regenerable Adsorption System (Project,
Azrafil, 2007). There are several process schemes. The simplest is a single stage
flow scheme. The inlet gas passes through the membrane system and the sales gas
exits the membrane at slightly less than the feed pressure.
Multistage systems allow the reduction of hydrocarbon losses on the permeate
stream. In the two stage flow scheme, the permeate leaving the first membrane
system is compressed and sent to a second membrane system. In that way, residue
gas is recycled to the inlet and the permeate leaves form the second membrane
system.
Figure 6 | PFD of a typical two-stage membrane unit
Figure 5 | PFD of a typical single stage membrane unit

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Membranes will permeate H2S from natural gas in roughly the same proportions as
CO2 is permeated. Membranes generally remove water down to 7 lbs/MMSCF.
2.3.3 Physical Solvents
Another method of acid gas removal is the use of possesses that rely on the
absorption of the acid gases into a physical solvent. Although the solvent may
contain small amounts of water to aid acid gas pickup, it is essentially a dry process.
These regenerative processes consist in the absorption of CO2 and/or H2S by
organic liquids at high pressures and ambient or low temperatures. The solubility of a
gas in a liquid is relatively low, and increases at higher gas partial pressures and
lower temperatures.
Regeneration is by flashing to atmospheric pressure and sometimes with vacuum,
but usually without heat. Selexol, Rectisol, Purisol and Fluor Solvent are commercial
examples of this kind of technology, this is done to minimize hydrocarbon losses,
flashes at an intermediate at an intermediate pressure and recompression/recycle
are employed. This extra equipment increases capital expenditures and fuel
consumption. Regeneration heat duties for physical solvents are low, but
considerable energy for compression is required.
The Selexol process, licensed by DOW and UOP, is described as its primary use is
for natural gas streams. Selexol is non-toxic; therefore high boiling is used in carbon
steel equipment and is an excellent solvent for acid gases, other sulfurous gases,
heavier hydrocarbons and aromatics. There are some process flow variations for
Selexol process. A typical unit will be described Figure 7.
The inlet gas is mixed with the rich solvent coming from the contactor column, then
cooled and liquids are separated before sour gas enters the contactor. Liquids from
the separator are flashed four times, one for methane recovery, one for high-
pressure CO2 release, one atmospheric flash and the fourth is a vacuum flash. In all
the expansions, acid gas is released and after the final flash, the solvent has to be
pumped to the contactor column. Lean solvent enters the top of the absorber while
the sour gas stream from the first separator enters the bottom of the absorber. As the
gas flows to the top of the absorber, acid gases are absorbed by the solvent.
Installation of an additional compressor must be evaluated to recycle high pressure

23
flash gases and reduce hydrocarbon losses. Additionally, depending on gas
composition, a refrigeration system is included in order to optimize the absorption.
The sweet gas comes out dry because of the high affinity of Selexol for water. It has
to be noticed that physical solvents also absorb heavy hydrocarbons.
Figure | 7 PFD of a typical Selexol unit
2.3.4 Cryogenics (ExxonMobil and Ryan Holmes)
2.3.4.1 ExxonMobil CFZ
Ross and Cuellar (Ross & Cuellar, 2010) discuss a cryogenic fractionation process at
the Sandridge Energy owned Century Plant, Fort Stockton, Texas to process 65 mol.
% carbon dioxide content feed gas. The overhead gas from the cryogenic de-

24
methaniser (21 mol. % carbon dioxide) is added to a SelexolTM
physical solvent
process for further carbon dioxide removal to meet sales specifications. The carbon
dioxide level in the de-methaniser overhead gas is dictated by approach to freezing
conditions. Whilst the “bulk” removal of carbon dioxide by fractionation minimises the
duty on the Selexol™ process, the low pressure carbon dioxide from the Selexol™
regeneration system requires significant recompression to boost it to storage
pressure. This combination of two process technologies makes good use of the
attributes of each but the production of low pressure carbon dioxide makes it unlikely
to be optimal for many potential applications. Cryogenic fractionation processes to
remove carbon dioxide from natural gas by freezing and subsequent thawing have
been proposed and are at various stages of technology development and
demonstration. These are ExxonMobil CFZ™, CryoCell® and Sprex®. Of these
CFZ™ is by far the most advanced (Oelfke, et al., 2013).
“Controlled Freeze Zone”, CFZ™ technology removes acid gas components by
permitting them to freeze in a specially designed section of a fractionation column to
then be melted and fractionated to strip light hydrocarbons so as to produce liquid
carbon dioxide product at elevated pressure. The sweet natural gas product meets
gas quality specifications.
Figure | 8 CFZ
TM
Principles of Operation (Charles, 2008)

25
CFZTM
was developed in the early 1980s and first demonstrated at a pilot plant in
Clear Lake, near Houston in 1986. This facility could produce natural gas containing
only 300 ppm of carbon dioxide and a carbon dioxide product containing only 0.5
mol%. methane. ExxonMobil has now completed a demonstration plant at its Shute
CREEK Treatment Facility in La Barge, Wyoming (Oelfke, et al., 2013). This was
used during 2012 and 2013 to asses CFZTM
performance over a wide range of gas
compositions to provide data to facilitate scale-up to fully commercial sizes.
ExxonMobil has identified capital cost, operating cost and efficiency improvements
(for production of carbon dioxide at high pressure for storage) over both Ryan
Holmes technology and cryogenic bulk fractionation with SelexolTM
tough just as with
these processes refrigeration requirements are high. CFZTM
can require more low
level refrigeration (at below -40º C). CFZTM
is proposed as a good technology choice
for processing raw gas containing as little as 8 mol%. carbon dioxide.
2.3.4.2 Ryan Holmes
Carbon dioxide solidification in the cryogenic de-methaniser and the inability to
produce sales gas quality methane can be resolved by extractive distillation, by
adding ethane and heavier hydrocarbons at the top of the column. This increases the
solubility of carbon dioxide in the liquid phase, increases operating temperatures and
raises the critical pressure locus so as to increase relative volatility and make
separation easier. As a result a sufficiently pure methane product, containing 4 mol.
% carbon dioxide or less, can be obtained and no further sales gas processing is
needed (Holmes & Ryan, 1982).
This technique was developed by Koch Process Systems and is named “Ryan
Holmes” technology. The carbon dioxide rich de-methaniser bottoms product is
contaminated with hydrocarbon solvent so further fractionation is then needed to
remove it. As a result the process can incur high refrigeration duties and high power
consumption. Refrigeration may be needed at lower temperatures than propane can
achieve (-40°C) unless solvent flows are increased (O'Brien, 1984), otherwise some
carbon dioxide needs to be evaporated to avoid needing ethane or ethylene
refrigerant.

26
Ryan Holmes technology has been discussed with a focus on the de-methaniser
operation. The upstream ethane recovery column uses Ryan Holmes technology to
break the carbon dioxide and ethane azeotrope prior to bulk carbon dioxide removal
to provide de-methaniser feed. This process system could just as well produce feed
to a CFZ™ column instead of the Ryan Holmes de-methaniser. This would avoid
carbon dioxide recycle. This combined Ryan Holmes and CFZ™ configuration could
potentially provide considerable savings in refrigeration, power consumption,
machinery cost and equipment cost and therefore substantially lower gas processing
costs.
2.3.5 Mixed Physical-Chemical Solvents
Several gas treating processes combine both a physical and a chemical solvent,
taking advantage of the benefits of both. Commercial examples are Sufinol, Ucarsol
LE and Flexsorb PS. The Sulfinol Process, licensed by Shell, uses a mixture of the
physical solvent Sulfolane, water and either DIPA or MDEA, both chemical solvents.
It is described as its primary use is for natural gas streams.
Sulfinol’s capacity to remove acid gases increases as their partial pressure
increases. Like most physical solvents, Sulfinol has a significant affinity for heavy
hydrocarbons and specially aromatics. The Sulfinol Process uses a conventional
absorption and regeneration cycle, similar to the one employed in the amine
processes. The sour gas is contacted counter-currently with lean solvent at
essentially ambient temperature and elevated pressures. The rich solution is flashed
at an intermediate pressure to release absorbed hydrocarbons. The solvent
regeneration is accomplished in a regenerator column which operates at low
pressure and elevated temperatures. Gas is not dehydrated in the contactor.

27
Figure | 9 PFD of a typical Sulfinol unit
2.3.6 Physical Adsorption
In adsorption processes, certain gas molecules are held on the surface of a solid.
Carbon-based adsorbents and molecular sieves are typical examples.
Molecular sieves are crystalline sodium-calcium alumino-silicates that can remove
H2O, CO2, H2S, and sulfur compounds from gas streams. Molecular sieves act like
“sieves”, trapping molecules larger than the pore diameter but allowing molecules
smaller than the effective pore diameter to pass through the bed. Molecules with a
polar structure have the greatest affinity for adsorbing to the sieve surface as there is
an electric charge on the surface area of the crystal lattice. The adsorption strength
of CO2 is somewhat lower than the one of H2S.
Molecular sieves are non-toxic, non corrosive and available in different pore sizes.
The typical flow scheme consists in two adsorption vessels: while the gas is being

28
sweetened flowing down through one vessel, regeneration and cooling is occurring in
the other.
As molecular sieves adsorb most preferably polar molecules, water is strongly
adsorbed by them. So different zones can be identified in a molecular sieve bed,
where water occupies the position closest to the inlet followed by H2S and CO2.
During adsorption, spent zones progress towards the outlet, and when the key
contaminant reaches it, the bed must be regenerated (Mokhatab , 2012).
A small portion of the sweetened gas is taken to a regeneration gas heater and then
flows upward through a spent molecular sieve bed. A portion of the heat in the
regeneration gas is transmitted to the molecular sieve, increasing the temperature
and desorbing contaminants. The sour regeneration gas is then flared. When
regeneration is completed, the second tower is cooled with sweetened gas.
Figure 10 | PFD of a typical physical adsorption unit

29
2.4 CO2 storage in depleted oil and gas reservoirs
Presently, policy for reducing the amount of CO2 in the atmosphere is sequestration
of CO2 in mature or depleted oil reservoirs. On the other hand, CO2 sequestration in
an oil reservoir is a complex issue covering a broad scope of technological, scientific,
economic, regularity and safety issues (Krumhansl, et al., 2002).
The main advantages to why oil and gas reservoirs are attractive targets for CO2
sequestration can be listed as:
 Structural traps which have accommodated the gas or oil over geological
timescales are ought to contain carbon dioxide, assuming increased pressure
does not create any new pathways to the surface or through the extraction
process
 Many studies have been done on the geological structure and physical properties
of most oil and gas fields.
 Computer models have been utilized in order to forecast the displacement
behaviour and trapping of CO2 for EOR (Grimston, et al., 2001)
 The reservoir will not be environmentally degraded by the CO2, as the reservoir
has already contained hydrocarbons
 While some production wells may be converted to gas injection wells, the others
may be used to monitor the behaviour of the CO2 within the reservoir. CO2
sequestration plan can be adopted for to improve oil production, if the field is still
producing (Gallo, et al., 2002)
2.5 Cost of CO2 sequestration
CO2 sequestration economy includes three distinguishable stages: CO2capture from
the source followed by dehydration and compression, Storage site transportation.
Storage and injection of CO2 into a geological storage is the last stage.

30
CO2 captures costs are relatively high. The range of CO2 removal from the exhaust of
gas processing power are approximately in the range of 40-60 $/tCO2. However,
capture costs can be minimized by utilizing exhaust gas streams with high-purity
CO2, which are emitted by several industrial processes (Herzog & Golomb, 2004).
The cost of transport is low compared to their costs. Transport costs vary between 1
and 3 $/tCO2 per 100 km of pipeline (Programme, 1998). Transportation costs can be
minimized if the reservoir is close to the carbon emission sources.
Geological storage costs differ by the reservoir and the local geological conditions.
For example, for gas and aquifers reservoirs (off and onshore) storage cost varies
between the range of 1-15 $/tCO2. On the other hand if enhanced oil and gas
recovery is employed by the injection of CO2 into oil/gas reservoirs or deep un-
minable coal steams, storage costs may be decreased significantly to small (or even
negative) by generating oil/gas revenues (Damen, et al., 2005)
2.6 Oil recovery by CO2 injection
Carbon dioxide in its liquid and dense phase is a very good solvent for hydrocarbons.
This makes it an ideal gas for use in accessing oil that cannot be produced under
natural pressure drive or from pumping. When in contact with CO2 at reservoir
conditions, oil swells and becomes less viscous. The CO2 also selectively dissolves
in the lighter oil fraction (and hydrocarbon gases). Carbon dioxide enhanced oil
recovery is therefore most effective for lighter oils, but it can also improve production
from heavy oils when combined with thermal techniques. When dissolved in water,
carbon dioxide has the ability improve porosity and permeability through the
dissolution of carbonate (if present). Furthermore a successful EOR operation is to
achieve maximum contact between the oil and the CO2 into the reservoir so that the
CO2 is at miscible or near-miscible pressure with respect to oil. After primary
production, oil fields are at reduced pressure compared to their original pristine state.
Water may then be injected to push oil to the production wells. This “water flood”
phase is known as secondary recovery. Potentially recordable oil that still remains
after the water flood is then targeted by CO2. This is known as tertiary recovery
Figure 11 shows an illustration of CO2-EOR concept.

31
Figure 11 | Carbon dioxide enhanced oil recovery concept (Mogollong, 2015)
The technique used is “water alternating gas” (WAG), which involves alternating
injections of dense phase CO2 and water in order to produce the remaining oil as
quickly as possible. Depending on the field characteristics, this tertiary phase can
produce an extra 5-15% of the original oil in place and extend field life by several
decades. The injected CO2 is guided through the parts of the field where recoverable
oil still remains. This is done by injecting water, along lines of boreholes positioned
either side of the reservoir area to be swept by the CO2 so as to produce a corridor of
diminishing pressure gradient, focussed towards the production well. These well
layouts are known as “panels”. The CO2 and water are removed from the produced
oil and gas, and reinjected. In WAG, the final injection of a panel is by water, so as to
flush out all the recoverable oil and CO2. Another potential method of CO2-EOR
which has yet to be attempted commercially is by using gravity-stable gas injection
(GSGI). This involves injecting CO2in the region of the original oil-water contact (oil
floats above water) in the oil-field flank. Over a long period of time the field is re-
pressurised. The rising CO2-oil front sweeps the oil to the production well on the crest
of the field structure. The extra oil produced using this method is significantly greater
than for WAG, but it takes many years before production is stimulated; hence it is
less attractive commercially over the short-to-medium term. The volume of CO2 used
(and therefore passively stored) is much greater than with WAG.

32
2.7 Oil recovery mechanisms by CO2 injection
Regardless how CO2 injection is carried out, whether as a miscible or as an
immiscible gas displacement, this is described in chapter 1.1.3 and regardless of how
it is applied in the field, following mechanisms are very important in the oil recovery
by CO2injection (Holm & Josendal , 1974):
 Oil viscosity is reduced: CO2 saturates crude oils which results in a significant
reduction in their viscosities at increasing pressures. As pointed out in the
literature, a more significant reduction is seen in the viscosity of the more viscous
crude so the mobility ratio increases.
 Extraction and vaporization of oil: CO2 can vaporize and extract portions of crude
oil. This occurs at low temperatures where CO2 is liquid, as well as the higher
temperatures above the critical, 89 ºF.
 Miscibility effects; CO2 is highly soluble in water and hydrocarbon oils.
 CO2 reduces the interfacial tension between water and oil.
 Increase in the injectivity (acidic effect): the acidic effect of CO2 on the rock has
been shown to increase the injectivity of water by direct action a carbonate
portions of the rock and by stabilizing action on clays in the rock (Holm &
Josendal , 1974).
The importance of the mechanisms listed above depends on the CO2 displacement
miscibility. That being said, the vaporisation of crude oil, miscibility variations and
interfacial tension reduction are crucial for the miscible CO2 process. On the other
hand, the reduction of crude oil viscosity and its swelling are more important for the
immiscible CO2 displacement (Holm & Josendal , 1974).
2.8 Ongoing CO2 projects
Figure 12 shows the multitude of research and commercial CO2 storage projects
existing around the world. The Industrial scale projects which are defined by projects
in the order of 1 MtCO2 yr-1 or more are the Sleipner project in the North Sea, the
Weyburn project in Canada along with the In Salah project in Algeria. This later has
been suspended after analysis of the reservoir, seismic and geomechanical data

33
from 2010 (Wright, 2009). It is believed that about 3-4 MtCO2 is captured and stored
yearly in geological reservoirs instead of releasing it into the atmosphere. Table 3
shows additional projects with detailed injection rates and total planned storage.
In addition to the Carbon Capture and Storage (CCS) projects currently in place, 30
MtCO2 is injected yearly for enhanced oil recovery, mostly in Texas, USA, where
EOR was initiated in the early 1970s. Most of this CO2 is captured from natural gas,
CO2 injected for EOR is produced with oil, from which it is separated and then
reinjected (Metz, et al., 2005).
Figure 12 | Location of sites where activities relevant to CO2 Storage are or under way (ADCO, 2010)
The first CO2 injection pilot plant was implemented in the Middle East in Rumaitha by
ADCO. Injection of CO2, supplied by Masdar, was begun in November, 2009 (ADCO,
2010)

34
Table 3 | Current and planned carbon capture and storage projects (Metz, et al., 2005)
Project Country Injection
start
(year)
Average
daily
injection
rate
(tCO2/day)
Total
(planned)
storage
(tCO2)
Storage
Type
Weyburn Canada 2000 3,000-5,000 20,000,000 CO2-EOR
In Salah Algeria 2004 3,000-5,000 17,000,000 Depleted
hydrocarbon
reservoir
Sleipner Norway 1996 3,000 20,000,000 CO2-EOR
K12B Netherlands 2004 100 8,000,000 CO2-EGR
Frio U.S.A 2004 177 1600 Saline
formation
Fenn Big
Valley
Canada 1998 50 200 CO2-ECBM
Quishui
Basin
China 2003 30 150 CO2-ECBM
Yubari Japan 2004 10 200 CO2-ECBM
Recopal Poland 2003 1 10 CO2-ECBM
Gorgon
(planned)
Austria 2009 10,000 Unknown Saline
formation
Snohvit Norway 2006 2,000 Unknown Saline
formation

35
3. Methodology
3.1 Aim and objective
The objective of this Thesis discussed in section 1.2 will be acquired by following the
detailed procedures indicated below:
 Extensive research will be conducted in understanding the different technologies
listed in chapter 2.2, the research will be directed into specific parameters which
are listed in the next section.
 In order to quantify each technology with respect to a specific parameter, data will
be collected from various sources including commercial and scientific references,
online public databases and companies and organisation data provided to the
general public. The main sources of information will be acquired from the Golf and
U.S.A implemented industries that have experience with CO2-EOR.
 Following the data collection, a performance index and logical pattern will be done
to distinguish the best technology as described in the next section. The
information will be tabulated with scores given according to the performance of
each technology respective to each key parameter. This will results in a valuable
comparison between the different technologies and the application where they
could mostly be exploited.
 The conclusions of this thesis will be derived from the summation of the weighted
scores developed in section 4. The results drawn from each section in the
dissertation will consist of a quantified method which narrows all the research into
a single and explained result.
 The conclusions will be summarised in a clear and concise manner in order to
offer the potential to be extended into additional studies if possible.
3.2 Evaluation methodology
As described above, there exist many processes to remove CO2, this makes the
selection process a critical concern as each of the processes has their own
advantages and limitations relatives to others, the major factors affecting the process
selection are listed below.

36
The Six methods have been evaluated and the results are tabulated in Appendices 1,
Table 6. The analysis of key parameters for all the processes are described below
and are based on the following key parameters:
 Project Execution
 CO2 Composition in feed Gas
 Economic
 Ease of Equipment Design
 Maturity
 Health and Safety impact
 Energy costs
 Market conditions (materials cost, consumables costs)
 Technology evolution with time
 Company experience with a certain technology
Each key parameter has been given a maximum weight factor of 3. The maximum
weighted score for each key parameter has been kept the same for the purposes of
this study and are defined as follow:
3 Important
2 Required
1 Not critical
Each Key parameter is allotted a maximum possible raw score of 5 and is evaluated
based on the information made available in actual literature and public database.
Based on quantitative and qualitative assessment, each Key-parameter has been
scored for each Option. The highest achievable raw score is 5 and the lowest is 1
and is defined are follows:
5 Outstanding
4 Better than expected
3 Acceptable
2 Less than expected
1 Unacceptable

37
Wherever the differentiation is not obvious, the same raw score has been assigned.
The total raw score for each key parameter is proportioned to a weighted score
obtained by multiplying the raw score by the weight factor. The aggregate weighted
score for the key parameters is calculated by summation. This aggregated weighted
score is not absolute but shows the relative differences between the different process
options based on the described evaluation. The process options are ranked for their
technical acceptance based on the aggregated weighted score. This technical
ranking shall be used in this thesis to determine the most appropriate process
application for the removal of CO2 from natural gas.

38
4. Evaluation of each option
4.1 Project execution
Project execution is considered as an important criterion in selecting the best suited
process and therefore given a weighing factor of 3. The importance of project
execution lies in the optimization of the implementation and the economics of CO2
removal processes. Very few projects exist in the world for combined CO2 capture
and injection for enhanced oil recovery as described in chapter 3.7.
Chemical Solvents using Amines, such as MDEA, for the removal of acid gases, are
widely used in gas processing and LNG plants. Numbers of amine related
technologies have been implemented in the industry. This cumulated experience
makes it project execution easier to design and implement. Two widely known
process licensors BASF and UOP have extensive AGRU experience and references
for onshore and some for floating facilities such as FPSO. Existing gas processing
plants generally accept a higher CO2 specification in treated gas than is allowable for
LNG applications. BASF and UOP have supplied several references to meet <50
ppm of CO2 in treated gas for onshore applications.
BASF’s experience is based on more than 390 reference plants in total which include
15 BASF-operated plants.
UOP has been selected as technology supplier for gas treatment in both on-shore
and offshore plants. About 40% of the world’s licensed gas treatment is performed
using UOP integrated solutions for LNG pre-treatment. UOP is also well experienced
in designing gas treatment units for offshore facilities.
Chemical Solvent Process using amine such as MDEA has been given a high score
of 4 for the following reasons:
 Their experience in meeting specification in onshore LNG plants for a range of
CO2 in feed gas varying between 12 and 0.2 % ,
 The guaranty offered by the process licensor considering their existing experience
in combined CO2 removal and CO2 injection in exiting plants.
The efficiency and performance of cryogenic fractionation actually increases as feed
gas carbon dioxide level increases. Low temperature Processing of Carbon Dioxide

39
Rich Gas GPA Annual Conference, Madrid, 17th – 19th September 2014 processing
has been reported as especially attractive for removing carbon dioxide from natural
gas containing over 20 mol. % carbon dioxide (Timmerhaus, 1983). Costain has
developed cryogenic fractionation technology to remove carbon dioxide from
hydrogen-rich synthesis gas on gasification based power plants and from oxyfuel
fired flue gas and this technology uses similar principles as for natural gas
processing.
The CFZ process is accomplished in a single cryogenic distillation column that can
produce a good quality gas as the overhead product. Although the process is dry and
would have low corrosion rates, the critical pressure of methane limits the operating
pressure to about 4100 kPa, thus making the range of its applications very low. The
conditions of the feed gas can require a very involved re-compression. A high arrival
pressure then favours absorption processes that work better at high acid-gas partial
pressures.
If the acid gas is recompressed and reinjected for environmental or oil- recovery
reasons, a process that delivers the acid gas dry and at high pressure is favoured.
The CFZ process has the added advantage of producing a liquid CO2 product that
could easily be pumped to higher pressure for reinjection. Because of the
advantages and limits shown above, this method is given an average score of 3.
The remaining technologies have no recorded industrial application to this day, for
the combined CO2 capture and injection and therefore they are given allow score of
2.
4.2 CO2 composition and percent removal in feed gas
CO2 composition and percent removal is considered as important criteria, if not the
most important in selecting the best suited process and therefore given a weighing
factor of 3. The importance of these criteria lies in the different feed gas compositions
in different plants, it is essential to choose a technology with capability of treating a
broad range of feed gas concentrations.
Figure 13 represents a simplified sweetening technology selection chart, where the
dotted line indicates the feed gas CO2 plus H2S content. The selection chart is used
for initial selection of a particular process, which may be based on feed parameters

40
such as CO2 composition, the nature of the impurities, as well as product
specifications.
Figure 13 | Gas sweetening selection chart (Project, Azrafil, 2007)
Feed percentage of acid/sour gas may be used as the second selection of the
different CO2 removal processes. In the case where CO2 is present in a significant
proportion compared to H2S, the selective process is preferred for the SRU/TGU
feed, and reduction of amine unit regeneration duty. The final selection could be
based on content of C3
+
in the feed gas and the size of the unit.
Figure 14 | Gas sweetening technology selection chart (Project, Azrafil, 2007)

41
From Figure 14, it can be seen that amines can treat a broad range of feed gas
concentrations and therefore remove a significant amount of CO2 gas. Amines can
treat feed gas concentrations in the range of 0.02 to 100% concentrations. Moreover,
chemical-solvent based processes allow a low amount of co-absorbed hydrocarbons.
For this reason amines are given a raw score of 5.
Physical solvents method relies on absorption for removal CO2, and therefore co-
absorption of hydrocarbons can be high. Even though physical solvent cover wide
range of acid gas concentration a score of 3 is given because of the hydrocarbon
carry over.
Physical adsorption method which uses selective molecular sieves can remove acid
gases at concentrations up to 1% to 2%, but are usually only cost effective at feed
concentrations less than 0.5%. For this, a score of only 2 is given as cover only low
acid gas concentrations.
From the chart above, membrane method covers only a small range of high acid
gases concentration. Membranes are not selective enough to avoid high hydrocarbon
losses. Another serious shortcoming is that membranes alone cannot produce high
quality gas. Consequently, additional processing must be done and therefore a score
of 2 is given for this method.
Mixed physical-chemical solvents are given a raw score of 4 as they can treat feed
gas concentrations in the range of 0.11-40%.
Another type of physical separation is cryogenic distillation means of treating gases
with high acid gas levels. Cryogenic distillation is best applied for acid gas levels
above 20% and could be applied in certain applications down to levels of
10%.Conventionaldistillation can only remove CO2 to a level of about 15%without
encountering freezing of the CO2. The Controlled Freeze Zone (CFZ) process,
developed and patented by Exxon Production Research, accomplishes this
separation in a single distillation column with special internals to control the
CO2freezing. This type of process can be attractive when removing large amounts of
CO2 from gases. Cryogenic distillation also suffers from high hydrocarbon losses. A

42
score of 2 is given because this method only covers a low range of acid gas
concentrations (High levels only).
Mixed solvent is a hybrid solvent that has both chemical and physical absorption
components. These solvents are proprietary and can be custom blended to optimize
the gas treating solvent performance for a particular feed gas and therefore suited for
a wide range of acid gas concentrations. For this a score of 4 is given.
4.3 Economic
Economic is also considered as important criteria, however very few data are
available to quantify the analysis of each technology, for this reason it will be given a
factor of 2.
Amine-based processes present important advantages such as low operating costs
compared to non-regenerable scavengers, as the chemical solvent is regenerated
continuously. The popularity of MDEA has been increasing. MDEA is usually applied
with proprietary activators to facilitate acid gas pickup. Its advantages are that it is
less corrosive and has lower regeneration heat duties
The physical solvent process has higher co-absorption losses to the acid gas stream
than the MDEA process that used a chemical solvent. The MDEA process had the
lowest equivalent cost for hydrocarbon losses
The amine based solvent process was given a score of 4 even if it did not have the
lowest capital expenditures or the highest thermal efficiency. Only by considering
both the capital expenditure and the impact of revenue losses due to operating
expenses and efficiency losses could justify the most economically feasible choice.
The main advantages of physical absorption are the relatively low operating costs
and ease of operation. As the compression of CO2 in physical absorption is costly,
this technology is mostly not recommended at low partial pressures (Biruh & Hilmi,
2009). In general, the economics of CO2 separation is strongly influenced by the
partial pressure of CO2 in the feed natural gas as mentioned above. To minimise
losses of hydrocarbon in physical absorption, flashes at an intermediate pressure
and recompression/recycle are employed. This extra equipment increases the capital
expenditures and fuel consumption. Regeneration heat duties for physical solvents

43
are low, but considerable energy for compression is required. For this reason this
technology of given a raw score of 3.
Membranes offer the potential of lower capital and operating costs than amine
systems, especially in smaller-scale units. The only significant operating cost for
single stage is membranes replacement. Multistage systems with recycle
compressors usually have comparable operating costs when compared to a standard
amine based flow scheme, considering membranes replacement is quite frequent in
such a process. Membranes are not selective enough to avoid high hydrocarbon
losses. Alternatively, higher capital and energy expenses for recompression and
recycle can be used to avoid those losses. This technology is given a raw score of 2.
Mixed chemical-physical solvent systems present a higher co-absorption of heavier
hydrocarbons and expensive chemical costs. In absence of H2S, the lean/rich heat
exchangers and the downstream rich-solution piping must be made of stainless steel.
As CO2 partially degrades DIPA, a reclaimer must be installed in this case, which
increases the costs of installation, for those reasons, it is given a raw score of 3.
The Controlled Freeze Zone (CFZ) process will require an addition of a downstream
process to remove the excess acid Gas and Hydrocarbon and therefore requires a
higher capital expenditure.
The Ryan-Holmes process has the potential for lower capital and operating costs.
The process eliminates the need for circulating solvent systems and very low
hydrocarbon dew points can be achieved. However, no large scale project has yet
used this technology.
Other advantages are that CO2 is removed at high pressure, reducing re-injection
compression horsepower, and CO2 dehydration is not required (Arif , 2008).
For the reasons listed above cryogenics will be attributed a raw score of 2.
4.4 Ease of equipment design
A factor of 1 is given to these criteria, as the ease of equipment design is very
subjective as it depends on variable plant operability.

44
Membranes design and installation is fast and relatively simple (membrane system is
modular and skid mounted), membranes present an advantage of simplicity and ease
of operation. Good weight and space efficiency, On the other hand membrane
method allows for high hydrocarbon carry over and consequently additional process
need to be done, this gives a raw score of 2 for this technology.
Adsorption processes are complex processes as very precise control is required. A
continuous synchronisation is required in the molecular sieves beds, as the beds
needs to switch from an adsorption mode to a regeneration to achieve significant
CO2 removal concentrations. This gives adsorption a very low raw score of 1 in these
criteria.
Chemical solvents processes have the advantage of being dictated by process
licensors as described in chapter 5.1.These licensors have brought along the past
years, significant experience in the design and implementation of this technology
This method is performed on a routine basis under the guaranty and supervision of
highly process licensors such as BASF and UOP, therefore a high raw score of 5 is
given for chemical solvent process.
Mixed chemical-solvents processes use a hybrid solvent that has both chemical and
physical absorption components. This method need to accommodate for custom
blending of solvents to optimize the gas treating solvent performance for a particular
feed gas This will make the equipment design more complex, The solvent's
absorption component have to perform both acid gas removal and a gas clean-up ,
For this, a score of 1 is given for this method.
Physical solvent technology has a patented Shell Design which has been
implemented quite significantly in the industry, especially when Shell is the operator.
A score of 4 is given for this method.
4.5 Maturity
Maturity is a very important criteria as it dictates the ability for future developments
into large scales operations, therefore it is given a factor of 3.

45
Initially, membranes were only operated in natural gas streams with high CO2 content
or those with small streams. Now that the membranes technology has improved and
is better known, it is used in many natural gas streams. The technology is believed to
have gained a certain maturity in the industry(Echt , 2008). The table below
underlines some key areas where the most mature technologies in this specific key
parameter.
Table 4 | Comparison of Amine and Membrane CO2 removal systems (Echt, 2008)
Operating Issues Amines Membranes
User Comfort Level Very familiar Still considered new
technology
Hydrocarbon Losses Very low Losses depend upon
conditions
Meets Low CO2 Spec Yes (ppm levels) No (<2% economies are
challenging)
Meets Low H2S Spec Yes (<4 ppm) Sometimes
Energy Consumption Moderate to high Low, unless compression
used
Operating Cost Moderate Low to moderate
Maintenance Cost Low to moderate Low, unless compression
used
Ease of Operation Relatively complex Relatively simple
Environmental Impact Moderate Low
Dehydration Product gas saturated Product gas dehydrated
Capital Cost Issues Amines Membranes
Delivery Time Long for large
systems
Modular construction is faster
On-Site Installation Time Long Short for skid-mounted
equipment
Pre-treatment Costs Low Low to moderate
Recycle Compression Not used Use depends upon
conditions
Considering the information presented in Table 4, which sums up all the criteria for
the two most mature technologies in industry. Amines will be given a raw score of 5;
again, the main reason for this high score is the existing licensors for the technology.
On the other hand, although membranes are seen as a new technology, it is
developing in a promising way; therefore it is given a raw score of 3.

46
The other technologies are given a raw score of 2, although they have significant
maturity in CO2 capture; however they have no maturity in the combined CO2 capture
and injection for enhanced oil recovery.
4.6 Health and safety impact
Health and safety is a very important criterion for the safety of workers and
environment, there is also a significant economic factor to be considered, and
therefore it is given a factor of 3.
In order to fulfil the goal following main principles have been adopted.
 The stress on inherent safety principles.
 Early identification of HSE hazards for the identified options.
 Stress the importance of HSE aspects while comparison is being made between
the prospective options.
 Ensure that the selected scheme is subjected to the conventional HSE in design
process).
The study process usually involves definition of the problem, identifying alternative
solutions to the problem, evaluation of the alternatives and selecting the right option.
Various options have been identified and evaluated to arrive at each key decision.
The importance of HSE issues has been stressed while evaluating the alternative
options. The evaluation is done qualitatively based on known facts. Some of the
options where the inherent risk is deemed to be high will have to be subjected to a
risk analysis process to ensure that the risk is within acceptable bounds.
All chemicals inherently are hazardous. Amine solvent, under uncontrolled
exposures, can be harmful to human health and on contact can cause chemical
burns. The key to safe operation is to recognize such hazards, evaluating their
potential to cause harm and then implementing appropriate risk management
practices and controls such that these risks are minimized, or even eliminated.
Amine solvent is a clear hygroscopic liquid with an amine odour. It is non-flammable
but can burn when ignited. On the basis of acute studies with laboratory animals,
Amine solvent is considered relatively harmful. MDEA, the main component of MDEA
has an oral LD50 value in the rat as 4.68 g/kg. Amine solvent generally does not

47
persist in the environment, and is readily biodegradable. It is also not expected to
bio-accumulate in organisms. However, because of its high pH value, it not advisable
to release untreated solvent into natural waters, and neutralization is required before
discharging into sewage treatment plants.
Chemical solvent process is given a raw score of 3 as MEA is corrosive.
Membranes system is environmentally friendly (as it does not involve periodic
removal or handling of large quantities of solvents or adsorbents). A raw score of 5 is
given to membrane process.
For the physical adsorption option, the sour regeneration gas needs to be flared or
treated separately in a physical absorption system. The CO2 content in the inlet sour
gas should be between 0.1 and 2% molar. Two or more beds are required to have
uninterrupted operation, this average raw score of 3 for the physical adsorption
option.
Cryogenics (ExxonMobil CFZ and Ryan-Holmes) systems require cryogenic fluids
which are flammable and toxic such as (acetylene’ ethane) which gives a low raw
score of 1.
4.7 Energy requirements
This is not a very important criterion but is significant as it is directly linked to the
economics; it is given a factor of 2.
Both the molecular sieve and the membrane have certain issues, which may limit
their usage. The molecular sieve uses a regeneration gas, which requires significant
amounts of energy. The membrane has a permeate gas which contains around 40%
methane together with the CO2 and therefore raise some issues as to handling this
gas. The best solution is to use both of these gases as fuel for the turbine. This
however requires the turbine design to be adjusted accordingly. (Haugen, 2011), this
gives a raw score of 2.

48
Significant hydrocarbons quantities are lost in with permeate gas in membranes
system. Hydrocarbon losses to the permeate stream show an exponential increase
with the percentage of CO2 removed as shown in Figure 15.
Figure 15 | Effects of CO2 removal (Project, 2007)
The permeate stream is at low pressure and requires compression to recover
hydrocarbons in a two stage system.
High feed gas pressure is necessary to provide the driving force for permeation. If
compression is required, the power requirement can be high.
A pre-treatment system is required to avoid membrane deterioration due to solid
particles, liquid hydrocarbons or water, and other contaminants.
For processes where the CO2 partial pressure is lower than 2 bara and CO2 is main
gas to be remove, Sulfinol-D is the most recommended technology based on the
lower energy requirements. Above a CO2 partial pressure of 3.5 Bara the ADIP-X
technology is more attractive due to its higher loading capacity, i.e. reducing capital
and energy requirements. Between 2 and 3.5 Bara both technologies are competitive
with respect to capital/energy requirements, and selection depends on process line-
up and integrate process options. (Groenen, et al., 2008), this gives the physical
absorption process a raw score of 5.Low to zero heating is required for regeneration
0
4
8
12
16
20
0 20 40 60 80 100
Percentage CO2 Removal
RelativeAreaorLosses
Membrane Area
Hydrocarbon
Losses

49
is physical solvent system because of the low heat of absorption. Selexol allows
equipment materials to be mostly carbon steel due to its non-aqueous and inert
chemical characteristics.
High degrees of acid removal are achievable with lower energy consumption and
lower circulation rates in mixed chemical-physical solvents than in conventional
amine plants under certain conditions, which gives it a raw score of 4.
Cryogenics (ExxonMobil CFZ and Ryan-Holmes) require very high energy for
regeneration, which increases the operating cost, therefore a raw score of 1 it
attributed to this technology.
4.8 Market conditions (materials costs, consumables costs)
Market conditions will be attributed a factor of 2 as CO2-EOR is only present in the
USA and Arab countries to this day. However it is in promising development.
Corrosion is a major concern that must be addressed with an appropriate materials
selection, for this reason, most of the process piping and vessels in amine plants are
built with carbon steel, meeting NACE MR0175 guidelines using stainless steel in
some areas (NACE MR0175 guidelines).
In addition to this, amines are circulated continuously and do not require
replacement, this present a significant advantage for the material cost along with
consumables costs. For these reasons, chemical solvent process is given a raw
score of 5.
As mentioned in chapter 5.3 membrane process requires changing frequently, this
present a significantly high cost, however no cost for solvents is required for this
technology, an average raw score of 3 is attributed to the membrane process.
A raw score of 2 is given to the other technologies, as they are not well established in
the industry.

50
4.9 Technology evolution with time
This is a crucial criterion, especially for companies that are willing to invest into one
of the technologies for enhanced oil recovery, a factor of 3 will be attributed to this
criteria.
Although membrane technology for CO2 removal has improved significantly in recent
years, it is still only used for low volume gas streams in natural gas processing.
Therefore it cannot compete with the standard amine absorption as the flux and
selectivity of the membranes are too low for processing large gas volumes, (Biruh &
Hilmi, 2009). This gives a raw score of 3 for the membrane process.
Chemical solvent is the technology which shows the most evolution up to now as it
has strong process licensors such as BASF and UOP. Each licensor has had to
assess the impact of varying application on their design. UOP and BASF have done
sufficient modelling, backed up by pilot plant test work, to have the confidence to
offer process guarantees for their designs. Therefore this method is given a raw
score of 5.
Again, a raw score of 2 is given to the other technologies, as they are not well
established in the industry.
4.10 Experience with combined CO2 removal and injection
The current utilisations of CO2 are majorly present in the Middle East and Algeria and
they are limited to mainly industrial purposes. The main utilisation of CO2 in the Arab
World is on the field EOR. For example, Abu Dhabi initiated a promising project plan
to capture CO2 from major existing stationary large-scale emission sources and
delivering it to oil fields for EOR purposes (Abu Dhabi Future Energy Company).
The project is budgeted at $2 billion and has the promise to reduceCO2 emissions by
removing around 90% of the CO2produced, and permanently storing up to 1.7 million

51
tons of CO2 per year into geological formations. This is believed to be equivalent to
decarbonizing Abu Dhabi’s entire domestic sector (Algharaib, 2009).
4.10.1 SACROC project
The SACROC unit project was initiated by Chevron in the early 1970’s and it was the
first commercial CO2-EOR project, it is still considered as the world’s largest miscible
flooding project today (Langston, et al., 1988), the unit covers 50,000 acres and was
developed to optimise secondary and tertiary recovery of oil in the Canyon Reef. The
project is still going and produces approximately twenty thousand tons of enhanced
oil production per day (O&G, 2006). Until now, the injection of CO2 has resulted in an
incremental oil recovery of approximately 10% of the HCPV (Dobitz, 2006).
Since the initiation of the project by SACROC, CO2-EOR projects continue to grow
around the world especially in the U.S.A and the Arab Golf as shown by Figure 16. a
more detailed picture is presented in the data shown Table 5, it shows the number of
large miscible CO2 projects in the U.S.A in relation to fluid, geological and production
parameters.
Table 5 | Large Carbon Dioxide Miscible Projects in the U.S. (O&G, 2006)
Field State Start Year Depth (ft) Oil Production (B/D)
Total Enhanced
SACROC Unit TX 1972 6,700 31,200 29,300
Wasson TX 1983 5,200 34,500 28,990
Rangely TX 1983 5,300 23,500 22.700
Means CO 1986 6,000 15,300 11,600
Wasson TX 1983 4,300 10,000 8,700
North Hobbs TX 1984 5,100 9,230 8,440
Salt Creek TX 1986 6,300 9,200 6,800
West Mallalieu MS 1986 10,550 6,500 6,500
Anton Irish TX 1997 5,800 5,850 5,400
Vaccum NM 1981 4,500 6,200 5,200
Codgell TX 2001 6,800 5,450 5,010
Postle OK 1995 6,200 5,000 5,000
Slaughter Sundown TX 1994 4,950 5,950 4,747
Lost Soldier WY 1989 5,000 4,672 4,545
Wasson (Willard) TX 1986 5,100 4,800 4,050
Salt Creek WY 2004 1,900 3,900 3,900

52
Figure 16 | U.S. Oil Production from CO2-EOR Projects by Year (O&G, 2006)
Membrane separation facilities are operating at both the Sun and Chevron CO2
processing plants of the SACROC tertiary oil recovery project in West Texas
Membrane gas separation. Membrane gas separation at both facilities began in
December 1983. The SACROC project has proven that membranes can be
commercially successful for large scale CO2removal; however the original Sun and
Chevron CO2 removal facilities use the Benfield hot promoted potassium carbonate
process. Monsanto uses the monoethanolamine (MEA) process (Parro, et al., 1987).
4.10.2 SLEIPNER project
The Sleipner project was amongst the first projects to use CO2 injection to reduce
emissions the atmosphere out of concern for climate change, Figure 17 shows an
illustration of the project. The Sleipner West part started production in 1996 has a
project life of 25 years. The process selected for capturing CO2 was the use of amine
solvent. This is a well-established process for this purpose (Tore , et al., 2006).

53
Figure 17 | The Sleipner field with CO2 injection (Statoil)
4.10.3 The WEYBURN project
The Weyburn project was the first EOR project to rely entirely on anthropogenically
produced CO2, for this reason this project will not be analysed in this paper as its
CO2 is not captured from natural gas (Tore , et al., 2006).
Considering the points mentioned above for all the projects listed, chemical solvents
technology is given the highest raw score of 5, membrane technology is given a raw
score of 4. The rest of the technologies are given a score of 2 as they are yet to be
implemented into large scale projects.

54
5. Conclusions
Amines, mainly DEA and MDEA, based processes are today the most widely used,
most versatile and cost effective technologies for all natural gas sweetening
applications. Amine processes are among the safest and most reliable, based on a
considerable industrial experience. These amines processes have been continuously
improved and updated, they now offer specific advantages over open art and other
competing technologies. Furthermore, ongoing R&D done by the cited licensors, will
continue to bring to the market technological improvement/innovations such as new
activated MDEA process which will further extend the limits of this technology.
The selection process for CO2 removal processes from natural gas were evaluated
through a performance index combining all the factors which can influence the choice
of the best process. Amine based solvent methods ranks highest with a weighted
score of 98. The other methods have lower score due to the quality of existing
information and extent of their applications. The evaluation can be summarised as
follows:
 Process licensors for chemical absorption methods using amine solvents with
proprietary activators are prepared to provide a guarantee of CO2 specification in
treated gas for large ranges of CO2 contents in feed gas.
 The large application in the industry of the removal of acid gases using amine
technology make its project execution more easy to design and implement
 Chemical-solvent based processes allow a low amount of co-absorbed
hydrocarbons.
 All other methods allow higher hydrocarbon carry over.
 Except for the mixed solvent method, all the other methods cover only a small
range of high acid gases concentration.
 The amine based solvent process does not have the lowest capital expenditures
or the highest thermal efficiency, but combining capital expenditure and the
impact of revenue losses due to operating expenses and efficiency losses could
justify its economic feasibility choice.
 Membranes system is environmentally friendly (as it does not involve periodic
removal or handling of large quantities of solvents or adsorbents).

55
 If the acid gas is recompressed and reinjected for environmental or oil- recovery
reasons, a process that delivers the acid gas dry and at high pressure is
favoured.
The CFZ process can produce such dry fluid and has the added advantage of
producing a liquid CO2 product that could easily be pumped to higher pressure for
reinjection. Although the process is dry and would have low corrosion rates, the
critical pressure of methane limits the operating pressure to about 4100 kPa .The
conditions of the feed gas can require a very involved re-compression. A high arrival
pressure then favours absorption processes that work better at high acid-gas partial
pressures.
Use of amine solvent is the recommended process technology to achieve the CO2
capture for EOR requirement. This method presents a significant advantage for its
project execution and implementation. It covers a wider range of application for a
wide range of CO2 content in feed gas. This method also allows strong removal
capabilities for very high treated gas specifications. Finally this amine solvent
technology has a better experience in the industry for the combined CO2 capture and
injection.

56
6. Future work and recommendations
Enhanced oil recovery (EOR) is increasingly being considered as a way of obtaining
revenue from sequestering carbon dioxide and cryogenic fractionation is especially
appropriate for processing the arising carbon dioxide rich associated gas to recover
high pressure carbon dioxide for recycle to the oilfield.
The need to extract NGL prior to carbon dioxide removal favours the use of Ryan
Holmes technology but this can incur high capital cost due to the recycle of
hydrocarbon for both ethane removal and avoidance of carbon dioxide solidification
in the de-methaniser. Using Ryan Holmes NGL removal technology upstream of a
CFZ™ column (in place of a Ryan Holmes de-methaniser) could provide savings in
refrigeration, power consumption, machinery cost and equipment cost. This approach
(and a related one without ethane recovery) could be of major importance in reducing
carbon dioxide EOR costs and in simplifying processing in terms of design,
engineering, installation and operation. Gas processing costs are an obstacle to
carbon dioxide EOR and the proposed processes go some way to reducing these
costs.

57
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8. Appendices
8.1 Process selection evaluation table

Carbon Dioxide removal processes for Enhanced Oil Recovery

Carbon Dioxide removal processes for Enhanced Oil Recovery

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