Clean Energy Science and Technology Volume 1 Issue 1 (2023) doi: 10.18686/cest.v1i1.

32

Review Article
Recent progress in carbon dioxide capture technologies: A review
Guanchu Lu1, Zhe Wang1, Umair Hassan Bhatti2,*, Xianfeng Fan1,*
1
School of Engineering, The University of Edinburgh, Edinburgh EH8 9YL, United Kingdom
2
KAUST Catalysis Center (KCC), King Abdullah University of Science and Technology (KAUST), Thuwal 23955, Saudi
Arabia
* Corresponding authors: Umair Hassan Bhatti, umair.bhatti@kaust.edu.sa; Xianfeng Fan, X.Fan@ed.ac.uk

Abstract: The continuous increase in anthropogenic CO2 emissions is widely acknowledged as one of the main reasons
for global climate change. To address this issue, significant advancements have been made in developing CO2 capture
and utilization technologies that offer new solutions for mitigating carbon emissions and promoting a carbon economy.
In this review, we summarize the recent research progress in CO2 capture and separation technologies, including pre-
combustion, post-combustion, oxy-fuel combustion, chemical looping combustion and calcium looping combustion.
Among these technologies, post-combustion is seen as one of the most promising options for reducing CO2 emissions
from existing power plants, as it can be easily integrated into existing facilities without requiring major modifications.
Therefore, the second section of this article focuses on the various post-combustion processes and technologies, such as
physical absorption, amine scrubbing, dual-alkali absorption, chilled ammonia, membrane separation, and solid
adsorption, with a particular emphasis on most recent research reports. As amine-based chemical absorption is the most
leading post-combustion CO2 capture technique, the third section summarizes the recent development in amine-based
absorption technology by covering conventional and emerging types of absorbents such as single amine, blended amine,
biphasic amine, and non-aqueous amine processes. The different liquid absorption-based process is compared in terms of
regeneration energy consumption, CO2 intake capacity, and optimal operating conditions, and the comparison data is
summarized in tables. A critical literature review and comparison of various techniques show that non-aqueous amine
absorbents can be promising alternatives to the conventional monoethanolamine (MEA) process. The goal of this review
is to provide strategies and perspectives for accelerating the further study and development of CCS technologies.

Keywords: post-combustion technology; amine capture process

1. Introduction
The fast development of modern society has resulted in an increase in CO2 emissions from 1.95 billion
metric tonnes in 1900 to 34.81 billion metric tonnes in 2020. Each year, more than 30 billion tonnes of CO2 is
further emitted into the atmosphere, aggravating the climate change issue[1]. With CO2 emissions increasing
every year, the efforts Cesare Marchetti, an Italian physicist, proposed a method for controlling CO2 levels in
the air in the 1970s, in which the CO2 is collected at appropriate concentrated emission points and transferred
to the deep sea or underground caverns for permanent storage[2]. In 2005, IPCC Working Group III introduced
the concept of carbon capture and storage (CCS) in a special report and addressed the relevant technologies of
CCS[3]. The purpose of the IPCC report was to alert the policy-makers, engineers, and researchers about global
warming due to CO2 emissions and the need to develop practical solutions to deal with this problem[4]. Since
then, CCS has been widely recognised as an effective technology for reducing atmospheric CO2 levels and is
increasingly being used in industrial carbon capture[5–7]. In 2020, 26 commercial CCS plants were in operation
around the globe, with many in early development or under construction. Of these 26 operational plants, the
vast majority were used for natural gas processing, while others were used in power plants, fertilizers, ethanol

Received: 7 August 2023 Accepted: 6 September 2023 Available online: 25 September 2023
Copyright © 2023 Author(s). Clean Energy Science and Technology is published by Universe Scientific Publishing. This is an Open Access article
distributed under the terms of the Creative Commons Attribution-NonCommercial 4.0 International License (http://creativecommons.org/licenses/by-
nc/4.0/), permitting all non-commercial use, distribution, and reproduction in any medium, provided the original work is properly cited.
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 2/47

production, hydrogen (H2) and other industries. The estimated capacity of these plants to capture and
permanently store the CO2 is around 40 million tonnes of CO2 per year.
CO2 is used in the beverage industry, food preservation, urea manufacture, water purification, enhanced
oil recovery, cement production, and polymer synthesis, making the worldwide CO2 utilisation around 232
million tonnes per year[7,8]. However, only under 1% of the CO2 that is released into the atmosphere at this
time is used as a raw material in the aforementioned industries[8–11], clearly indicating that a rapid growth in
the efforts and scale of CO2 capture technology is required. An important pillar of CO2 abatement efforts is the
concept of circular economy, where captured CO2 can be used to make valuable commodities like petroleum
products and high-value chemicals. The carbon in CO2 molecules is thermodynamically stable because it is at
its highest oxidation state (+4), its chemical conversion to target chemicals is difficult, and therefore, energy
is required activate and convert CO2 through a redox reaction, where the CO2 is reduced (accepts electrons)[12–
14]
. Shifting the focus to CO2 capture involving conversion, the oxidation state reveals the existence of eight
distinct reduction levels, each yielding its unique product results and potential for synthesis. The redox reaction
highlights two essential aspects within the reduction procedure: the introduction of hydrogen and the
elimination of oxygen[15,16]. The redox reaction can undergo through photochemical, thermochemical,
electrochemical, and biological methods, each of which have distinct advantages[17]. The use of CO2 in resource
recovery in chemical and oil industry (Enhanced Coal-bed Methane Recovery, Enhanced Oil Recovery (EOR))
has the highest potential for non-captive demand[11]. The amount of CO2 utilised globally is below 200 Mt per
year, while the global anthropogenic CO2 emission is over 32,000 Mt per year[18]. The development of CO2
capture helps to accelerate the deployment of carbon capture utilization and storage (CCUS), which pays
attention to not only the storage of CO2 but also the use in industrial applications[19]. CCUS makes it possible
to allow the continued use of fossil fuels while maintaining stable concentrations of greenhouse gases in the
atmosphere. Every element within the CCUS value-chain, as illustrated in Figure 1, plays a vital role in
ensuring the economic and technical feasibility of the CCUS process.

Figure 1. Pathways of current technologies of CO2 production, capture and separation.

Currently, a significant reduction in CO2 emissions is required to align with the COP21 agreement. The
primary hindrance in implementing carbon capture and storage (CCS) is the massive economic penalty of a
CO2 capture unit that can ultimately increase the price of electricity by 33%. Currently, the estimated cost of
capturing CO2 using existing technology is ~$60 per metric tonnes of CO2[20] and a significant reduction in the
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 3/47

economic penalty is required to make CCS a profitable option and to attract investors from government and
private sectors. To overcome this challenge, the scientific community around the globe is putting their efforts
to reduce the cost of carbon capture to around $20 per metric tonnes of captured CO2[21].
Nevertheless, numerous technical hurdles confront the possible widespread integration of Capture in
power plants. Figure 1 outlines the streamlined routes of present CO2 production, capture, and separation
technologies. The current technologies of CO2 capture includes pre-combustion technology, post-combustion
technology, oxy-fuel combustion technology and chemical looping technology[22]. Direct air capture (DAC) is
a specific type of carbon capture that involves capturing carbon dioxide directly from the air using specialized
equipment, as opposed to capturing it from industrial sources or power plants[23–25]. DAC technology uses
chemical reactions to capture CO2 and remove it from the atmosphere. The key difference between DAC and
other carbon capture technologies is that DAC captures CO2 from the air, whereas other carbon capture
technologies capture CO2 from industrial or power generation processes. This means that DAC has the
potential to capture CO2 from a wide variety of sources, including sources that are difficult to capture using
other technologies, such as transportation or agriculture[26,27].
In this review article, we thoroughly review and analyse the recent innovations and advancement in the
carbon capture and storage (CCS) technologies. Section 1 focuses on the principles and recent research
advancements of the four major CCS technologies, i.e., pre-combustion CO2 capture, post-combustion CO2
capture, oxy-fuel combustion, and chemical looping combustion. Section 2 provides an overview of various
post-combustion processes, including process configurations and principles. Section 3 delves into
advancement in the absorption media by discussing and reviewing the novel amine absorbents, blended amine,
biphasic solvent, and non-aqueous absorbents. In Section 4, as an important part of CCUS, the CO2 utilization
is summarized. In Section 5, we summarize this paper and comparing and analysing the key benefits and
challenges of each technology. With an aim of analysing the recent research, the scope off this paper is to
summarize and analyse the research efforts and innovation made in the field of carbon capture technology after
2014.

2. CCUS technologies
CCUS technology includes technologies for CO2 capture, transport and storage, and CO2 utilization. The
CO2 capture alone accounts for more than 70% of all operating expenses of CCS[28]. Three main technologies
in practice for CO2 capture are pre-combustion CO2 capture, post-combustion CO2 capture, and oxy-fuel
combustion[29]. Chemical looping combustion is a non-conventional combustion method with an inherent CO2
capture capability. In the next section, we shall thoroughly summarize the developments and current status of
these technologies.

2.1. Pre-combustion CO2 capture technology

Pre-combustion carbon capture technology removes CO2 from the streams of fossil fuels or biomass prior
to combustion[30]. The conventional pre-combustion carbon capture technique layout is shown in Figure 2. In
the pre-combustion CO2 capture, fossil fuels first undergo a fuel conversion process where gasification takes
place. In the gasification process, fossil fuels are partially oxidized in steam and oxygen to produce syngas
(CO + H2), as described in Equation (1). The syngas is further transformed into CO2 and additional H2 by using
a catalytic reactor (also called a converter) (Equations (2) and (3)). The resulting hydrogen-rich syngas can be
used for power generation after the CO2 has been separated out. The pre-combustion capture approach is
primarily utilized in conjunction with either integrated gasification combined cycle (IGCC) or natural gas
gasification combined cycle (NGCC). Figure 3 displays the layout of the IGCC combination with pre-
combustion equipment.
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Figure 2. The process flowsheet of pre-combustion carbon capture.

������������
퐶표푎푙 ���������� 퐶푂 + 퐻� (1)

��������� �����
퐶푂 + 퐻� 푂 ������������� 퐶푂� + 퐻� (2)

������� ���������
퐶퐻� + 퐻� 푂 ���������������� 퐶푂 + 퐻� (3)

Figure 3. A schematic layout of an IGCC power plant using pre-combustion carbon capture. Reproduced with permission from Sifat
and Haseli[21].

In general, pre-combustion CO2 capture is environmentally friendly and energy efficient. It transfers
energy from carbon fuels to hydrogen fuels by gasification process[31]. The combustion product of hydrogen is
water, instead of CO2, and no other pollutants such as SOx are produced in this way as conventionally burning
the carbon fuels do. Although this process is complex and expensive than other CO2 capture technologies, the
high pressure (2–7 MPa) and a high concentration of CO2 (15%–60%) in the gas stream requires less energy
for CO2 separation and CO2 compression than other CO2 capture technologies[20]. Most recent research on the
pre-combustion CO2 capture technology is summarized in Table 1. Mainly, research efforts are focused on
reducing the thermal and economical penalties of pre-combustion capture technique. Park et al.[32] investigated
several physical absorbents in the gas separation process, and found the Selexol process the most energy-
efficient. Other advanced gas separation technologies include membrane separation, hydrate based gas
separation and ionic liquid separation[33].
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Table 1. Recent research progress of pre-combustion technologies.

Ref Year Separation techniques Key findings
[32] 2015 Selexol physical absorption Utilized three physical absorbents, in terms of energy consumption,
Selexol was discovered to be the most effective pre-combustion technique
[33] 2015 Amine-TiO2 adsorption Mesoporous amine-TiO2 was employed. This low-cost sorbent was stable
and readily regenerable without capacity or selectivity loss.
[34] 2016 Membrane separation Under high pressure and temperature, the separation performance of
ionic-liquid based membrane was tested, the separation effectiveness is
decreased in high pressure.
[35] 2016 Hydrate based gas separation The optimal concentration of tetrahydrofuran (THF) at 282.2 K and 6
MPa was 5.56 mol%.
[35] 2016 Hydrate based gas separation Hydrate-based carbon capture was found to be most suitable with the
combination of 5% TBF and 10% TBAB.
[36] 2018 Membrane contact separation Investigating the cost of CCS by using membrane contactor with PSA
process, which was not suitable for commercial usage.
[37] 2018 Ionic liquid physical absorption They demonstrated that utilizing ionic liquid for carbon absorption
provides comparable results to Selexol method.

2.2. Post-combustion technology

Post-burning capture (PCC), often known as the “end-of-pipe” CO2 separation technology, removes CO2
from flue gases after the combustion of fossil fuels or biomass. The left panel of Figure 4 provides a flow
chart of post-combustion CO2 capture. PCC technology commonly collects CO2-contained flue gas from
conventional oil, coal, and natural gas power plants’ flue emissions. Typically, low CO2 concentration flue gas
is released from the power plants at atmospheric pressure. The CO2 is selectively captured and then pressurized
through a compression unit before transporting it, while the CO2-free flue gas is released to the atmosphere.
PCC is currently the most widely used capture method because compared to the other carbon capture
technologies, it is easy to retrofit to existing power plants, can handle large gas volumes, and can achieve good
CO2 separation rate.

Figure 4. Left: process flowsheet of post-combustion carbon capture. Right: post combustion carbon capture power plant operating
with natural gas as the fuel. Reproduced with permission from Sifat and Haseli[21].

Nonetheless, there are several challenges to this post-combustion technique including high flue gas
temperature and significant parasitic load stems from the low CO2 concentration in combustion flue gas,
leading to associated expenses in operating the capture unit to enhance CO2 concentration (beyond 95.5%).
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This elevated concentration is necessary for effective transport and storage[38–40]. Large amounts of flue gas
containing low CO2 concentrations (typically 4%–14%) need to be treated, which requires a vast volume of
the separation unit and high capital investment as well. In addition, the flue gas also contains fly ash, NOx, and
SOx which need to be removed before the PCC, increasing the operation cost in the existing separation process.
Mainly, chemical absorption method is employed for post-combustion CO2 capture using alkanolamines as
absorbents.
Right panel of Figure 4 depicts the configuration of a natural gas power plant integrated with PCC. MEA,
a primary amine, is generally employed to scrub CO2. The burning of natural gas produces heat, which is
subsequently used to create steam. Then steam is transformed into electricity by steam turbines. In the absorber
column, MEA removes CO2 from exhaust flue gas, and the CO2-loaded MEA is regenerated in the stripper
column by heating up to 120–150 ℃, where high-purity CO2 is collected from the top of the stripper column.
Refreshed MEA is then recycled to the absorber column for cyclic use. Thermal degradation of amine
absorbent and high energy penalty for solvent regeneration are the main challenge of the PCC process. In
particular, the thermal energy required for amine regeneration accounts for up to 70% of the total operational
cost[41].
In efforts to enhance the PCC (post-combustion capture) process performance, innovative designs for
amine processes and absorbents have been proposed. Ahn et al.[42] have explored nine distinct process
configurations, each aiming to curtail the steam demand in the amine capture process. This reduction would
mitigate the extent of modifications needed in existing steam cycles when retrofitting a carbon capture unit to
a power plant. The study revealed that, in comparison to the conventional configuration, the integration of
absorber intercooling, condensate evaporation, and lean amine flash could bring about a 14.1% decrease in
total energy cost. Surprisingly, when taking stripper overhead compression configuration, the reboiler heat
duty decreased from 3.52 GJ/ton CO2 to 2.41 GJ/ton CO2. The stripper overhead compression configuration
reduced the energy consumption by maximising heat recovery at the heat exchanger. Non-aqueous MEA has
also been researched by Bougie et al.[43, 48]. Compared to 30 wt% aqueous MEA, the energy consumption of
20 wt% MEA in DEGMEE decreased by 78%. The primary factor contributing to decreased energy
consumption during absorbent regeneration is the low specific heat capacity of DEGMEE. Table 2 contains
more details of current research on post-combustion carbon capture processes.

Table 2. Recent research progress of post-combustion technologies.

Ref Year Separation techniques Abstract of techniques
[42] 2013 Chemical absorption Investigated 9 different amine process configurations and evaluating their total
energy consumption.
[44] 2016 Membrane absorption A mathematical model was proposed to identify the optimal operating parameters
for CO2 absorption in the hollow fibre membrane.
[45] 2017 Chemical absorption Investigated the carbon capture performance of more than 30 amine solutions. 2-
ethylaminoethanol was deemed superior due to its excellent CO2 absorption
capacity and low regeneration energy.
[46] 2017 Chemical absorption A two-stage stripping process was developed, where the secondary stripper utilizes
the wasted heat from the primary stripper, leading to a reduction in overall heat and
energy consumption.
[47] 2018 Membrane absorption A 2D model of piperazine membrane absorption system was proposed. For ideal
performance, the optimal gas velocity, CO2 concentration, and solvent are
investigated.
[48] 2019 Chemical absorption Non-aqueous MEA process was proposed. MEA/DEGMEE absorbent could
decrease the energy consumption by 78%.
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2.3. Oxy-fuel combustion technology

Oxy-fuel combustion is basically a modified post-combustion technology. Figure 5 provides a flow chart
of oxy-fuel combustion CO2 capture. In this technique, fuel is burnt in the presence a high-purity oxygen
stream (>90%) and thus major components of the flue gas stream are CO2 and water[49]. Air separation units,
typically cryogenic separation, are used to separate and concentrate the oxygen from the ambient air for
combustion. Another critical unit of this process is the boiler, also called the combustion chamber, which is a
key unit determining the overall thermal and economical penalty of oxyfuel combustion. Modern boilers can
significantly decrease SOx and NOx emissions and increases the fuel combustibility[21]. Since the flame
temperature in the boiler becomes too high when the fuel is burned in pure oxygen, recycling a portion of CO2-
rich flue gas into the boiler to decrease the burning temperature is generally required.

Figure 5. The process flowsheet of oxy-fuel combustion carbon capture.

Due to the absence of N2, the oxy-fuel combustion process can be more cost-effective than other
techniques for CO2 capture because N2 consumes a huge amount of energy during fuel combustion. Another
significant benefit of oxy-fuel combustion is that the flue gas contains a high concentration of CO2 (65%–
80%), in contrast to the flue gas of a conventional power plants where CO2 concentration is generally low (12
to 16%). Therefore, the final CO2 separation is achieved by condensing and knocking out the liquid water to
produce a high-purity stream of CO2. However, the researchers have discovered that oxy-fuel combustion
demonstrated 1%–5% less efficiency than other capture technologies[50]. Other drawbacks of oxy-fuel
combustion are high operating expense on high purity O2 production, the large amount of electricity consumed
in this process, and unavailability of a low-cost method to produce pure O2. Moreover, the concentrated high-
purity O2 collected in the combustion chamber of oxy-fuel technology leads to several problems, such as
corrosion, fouling, high maintenance costs, and safety issue[30,31].
Lately, research efforts are focused on designing novel boilers and energy-efficient O2 separation methods,
and evaluating the influence of recycled water vapour on flame temperature. Vellini and Gambini[51] analysed
and integrated the membrane separation process in an oxy-fuel combustion process. Their results have shown
promising performance, and the cost of CO2 decreased from €40 per tonne to €16 per tonne in IGCC. Further
membrane configuration to oxy-fuel combustion was studied by Falkenstein-Smith et al.[52], where a high CO2
selectivity is achieved (87.5%) through a novel oxygen transport membrane. Instead of flue gas, supercritical
steam is employed as the recycled media in Clean Energy Systems (CES)[53]. The fuel is combusted in the
boiler with supercritical steam, and then mixed gas-contained steam is transported to turbines for power
generation. This CES configuration is considered an option for application in the oxy-combustion of natural
gas. Latest research on oxy-fuel combustion is summarized in Table 3.
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Table 3. Recent research progress of Oxy-fuel combustion technologies.

Ref Year Abstract of techniques
[51] 2015 An examination was conducted on a revolutionary power plant utilizing a supercritical steam cycle, combined
with CO2 collection and the utilization of oxy-fuel combustion.
[52] 2016 An evaluation was performed on the CO2 selectivity and O2 permeability of a ceramic membrane catalytic
reactor.
[54] 2017 Super critical CO2 cycles was investigated in energy generating.
[55] 2017 An investigation was conducted on the impact of recuperator performance on a semi-closed oxygen combustion
mixed cycle.
[56] 2018 The thermal effect of CO2 concentration in oxy-combustion process, the non-liner temperature drops when CO2
was added.

2.4. Chemical looping combustion technology

Chemical looping combustion (CLC) technology is used to realize fuel combustion in a nitrogen-free
environment. Richter and Knocke[57] first proposed it in 1983 to reduce the energy loss of fossil fuel
combustion. IPCC has considered the CLC process as one of the cheapest carbon capture technologies[58];
hence, it attracts much interest from researchers.
There are two main reactors employed in the CLC process; one carrying air, called air reactors, while the
other containing fuels, called fuel reactors. The left panel of Figure 6 displays a schematic diagram of the CLC
process. In the air reactor, the reduced metal particles are moved to be oxidized by oxygen. The exit gas from
the air reactor mostly consists of nitrogen with a trace quantity of oxygen, and it is possible to direct purge into
the atmosphere without further purification[21]. After oxidation, the solid oxygen carrier flows to the fuel reactor.
In the fuel reactor, the fossil fuel is oxidized to CO2 and H2O while the metal oxides react with the fuel, then
the metal oxides are reduced to solid metal particles. These solid metal particles are also called metal oxygen
carriers (MOC) and are recycled in the air reactor.

Figure 6. Left: a CLC reactor with two fluidized beds. Reproduced with permission from Jin and Ishida[63]. Right: process flowsheet
of chemical looping combustion carbon capture.

Chemical looping techniques were initially designed for fluidized bed systems. Figure 6 displays a
conventional fluidized bed configuration of the chemical looping combustion process. The fossil fuels are fed
to the fluidized bed system through a screw or hopper. After interacting with the fuel, the reduced oxygen
carrier is sent back to the air reactor through a loop seal. In the CLC process, all forms of fuel are acceptable;
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 9/47

be it a gas fuel (syngas, natural gas, and propane), liquid fuel (diesel, asphalt, and heavy oil), or solid fuel (coal,
biomass and coke)[59–61].
The CLC process could achieve higher thermal efficiency than other carbon capture technologies, with
corresponding operating temperatures and pressures of 1200 ℃ and 13 bar in the air reactor. it was discovered
that the thermal efficiency of IGCC-CLC achieved 52%–53%, 2.8% higher than PCC-IGCC process in carbon
separation[59]. Also, the CLC process achieves 3%–5% higher carbon capture efficiency than other
techniques[62]; and 100% carbon removal efficiency can be achieved, while the chemical absorption is
generally limited to 95% removal efficiency[62].
Finding an appropriate oxygen carrier with a high fuel conversion ratio, excellent stability, and a high
oxygen transport capacity is a key component of CLC research[59]. Iron, copper, manganese, and nickel are
some of the most probable elements to act as oxygen carriers. More than 290 oxygen carriers have been
evaluated for the CLC process, and the nickel-based metal oxide is shown to perform better in a 10 kW
prototype reactor[64]. The recent research states of the CLC process and CLC oxygen carriers are summarized
in Table 4.

Table 4. Recent research progress of chemical looping combustion technologies.

Ref Year Research focus Abstract of techniques
[65] 2015 CLC rector A 1000 MWth boiler was designed for CLC process, the total cost of CO2 capture could as
low as €20/ton CO2.
[66] 2015 CLC process A 100 MWth CLC unit was designed and 95% CO2 capture efficiency was achieved.
[67] 2018 CLC process A 0.5 KWth biomass-CLC process was performed. Almost 100% CO2 capture can be
attained during CLC fueled by biomass without the requirement of stripping.
[68] 2016 CLC process 1 MWth CLC process with hard coal was operated. The converted hard coal in the boiler
decrease the CO2 removal efficiency, carbon stripper is needed for hard coal-CLC process.
[69] 2019 CLC process 1 MWth CLC process with natural gas was operated. The conversion efficiency of natural
gas achieved to 80%.
[70] 2020 CLC process Improved oxygen carrier was performed in CLC unit, the O2 demand was decreased from
9.6% to 4.1%.
[71] 2017 CLC carriers The iron-based, copper-based and calcium-based oxygen carrier was performed in CLC
process. Natural ores showed better performance than purified metal oxides.
[72] 2018 CLC carriers Cu-Mn mixed oxide was taken as oxygen carrier in biomass-CLC process. This novel Cu-
Mn oxygen carrier improve the CO2 efficiency to 98%.
[73] 2022 CLC carries Highly reactive NiFe2O4 oxygen carrier was studied for CLC process, the reaction rate of
NiFe2O4 is two times faster than conventional Fe2O3 oxygen carrier.

2.5. Calcium looping technology and integrated CO2 conversion

2.5.1. Calcium looping capture
The concept of Calcium Looping technology (CaL) was initially introduced by Shimizu in 1999[74].
Figure 7 illustrates the schematic diagram depicting the application of CaL for post-combustion CO2 capture.
In this method, CO2 engages in a direct reaction with CaO to generate solid calcium carbonate, which can be
conveniently separated from other gases. The fundamental reversible reaction underlying this process is the
carbonation reaction, which releases heat (exothermic), whereas the inverse reaction, referred to as the
calcination reaction, absorbs heat (endothermic). The reaction is presented below[75]:
�����������
퐶푂� + 퐶푎푂 ���������� 퐶푎퐶푂� (4)
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Figure 7. Calcium looping within a post-combustion capture process. Reproduced with permission from Bui et al.[76].

While the carbonation reaction displays an initial rapid pace, it gradually decelerates over time[77]. The
calcination reactor necessitates a substantial input of heat, often achieved through oxy combustion of coal or
natural gas at elevated temperatures[78]. Following retrieval from the calcination reactor, the CO2 is compressed
and stored. This process finds applicability in both pre-combustion and post-combustion approaches, where
the pivotal reaction in the gasifier for pre-combustion carbon capture is as follows[75]:
퐶푂 + 퐻� 푂 + 퐶푎푂 → 퐶푎퐶푂� + 퐻� (5)
The primary utilization of this process centers around post-combustion carbon capture, where limestone
is employed to capture CO2 from the exhaust flue gases of a power plant through a circulating fluidized bed
carbonator[76]. Subsequently, the sorbent is directed to a higher-temperature calciner for regeneration and then
cycled back to the carbonator. In the calciner, coal or natural gas is burned within an oxy-fuel environment to
produce the necessary heat. The overall reaction for solid carbonate formation is exothermic, and the high-
grade heat generated during carbonation can be used for a steam cycle to generate additional power. This helps
mitigate the energy penalty associated with traditional post-combustion capture[79]. The limestone (CaCO3)
used in this method is non-hazardous, readily available, and more cost-effective compared to amines typically
used for scrubbing in post-combustion carbon capture. Furthermore, spent sorbents can be repurposed for
secondary applications. While the sorbent is recycled and reused for CO2 capture, it’s important to note that
the reversibility of the core reaction diminishes with each cycle, resulting in a reduction in the sorbent’s overall
capacity[80]. The main cause of this receptivity decay is sintering and attrition. The capacity of the sorbent is
reduced by 15%–35% after the first cycle, depending on favourable and unfavourable conditions[77], but this
loss of capacity decreases in each cycle. Other natural materials such as dolomite (CaMg(CO3)2), oyster shells,
egg shells are also tested[81]. It was found that utilizing these materials in CaL cycles is economically feasible.
However, it is unlikely that the required quantities of these residues can be produced for the commercial
implementation of CaL. A significant amount of makeup sorbent is required for this process. The recent
research states of the CaL process are summarized at Table 5.

Table 5. Recent research progress of chemical looping combustion technologies.

Ref Year Research focus Abstract of techniques
[82] 2015 CaL sorbents An analysis was conducted to compare the performances of dolomite and limestone. Dolomite
have better performance.
[83] 2016 CaL sorbents Egg shell based CaO materials were developed, with being >55% conversion after 40 cycles.
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 11/47

Table 5. (Continued).
Ref Year Research focus Abstract of techniques
[84] 2016 CaL sorbents Compared to unmodified limestone, the CO2 absorption after 13 cycles was observed to increase
by up to three times for limestone doped with HBr.
[85] 2019 CaL sorbents The core-shell structured CaO-CuO/MgO sorbent was developed, this material is suitable for
CaL-CLC process.
[86] 2016 CaL process The CaL-CLC method had a greater process efficiency than CaL alone, and generates more
power output. (136 vs 110 MW).
[79] 2017 CaL process The CO2 cost of CaL process was calculated and estimated to €10.0/ton CO2 and €33.9/ton CO2,
depends on carbon source.
[87] 2018 CaL process The impact of impurities in flue gas were proposed through experiments under CaL process. The
NOx emission is also investigated.
[88] 2020 CaL process Coal-fired power plants was integrated with CaL process, the CO2 capture cost decreased to
$19/ton CO2. It proves the application potential of CaL process.
[89] 2020 CaL process Integration of supercritical CO2 cycle with CaL and to evaluate their benefits by Aspen Plustm.
The electricity price was 26% higher than reference unit.

2.5.2. CaO coupled with the metal-based catalysts for CO2 reforming
In recent years, significant attention has been devoted to high-temperature CO2 capture and in situ
utilization methods, which employ CaO along with commonly used catalysts like Ni, Fe-based, or small
amounts of noble metal-based materials. The use of inexpensive CaO at elevated temperatures allows for swift
and effective carbon capture. Furthermore, well-established catalysts such as Ni, Fe, or Cu-based ones can
facilitate industrially viable CO2 hydrogenation[83,90–92]. It’s noteworthy that the warming power of CH4
exceeds that of CO2 by a factor of twenty-two[93,94]. Presently, CH4 finds extensive use in generating H2 through
chemical looping reforming or steam methane reforming. A promising avenue involves the dry reforming of
methane (DRM) as outlined in Equation 4, wherein both major greenhouse gases are utilized. This integrated
approach, not only offers potential for tapping into low-carbon alkanes but also contributes to the mitigation
of CO2 emissions. Exploiting the catalysts for the DRM process to synthesize liquid fuels or high-value
hydrocarbons using Fischer-Tropsch approach presents a pragmatic pathway for the enhancement of
alkanes[95,96].

퐶퐻� + 퐶푂� ↔ 2퐶푂 + 2퐻� ∆퐻���� = 247 푘푗/푚표푙 (4)

The DRM procedure encompasses two primary phases: initial CO2 capture utilizing alkali metal oxides
and the subsequent dry reforming of methane facilitated by a catalyst. Among adsorbents, CaO-based materials
are widely favoured due to their alignment with the thermodynamic prerequisites of DRM. However, a notable
challenge within this process is the tendency of CaO to undergo sintering, a phenomenon of particle
coalescence. Furthermore, the efficacy of adsorbents in the DRM process is influenced by the presence of
catalysts[97].
The DFM process frequently employs catalysts such as Ni, Ru, Mo, or Co-based ones, which effectively
lower the thermodynamic barrier and consequently reduce the necessary reaction temperature[95]. The interplay
between metals and adsorbents holds a pivotal role in the DRM process. Tian et al.[98] scrutinized two forms
of NiO within CaO-Ni bifunctional sorbent-catalysts. The proportion of interacting NiO expanded from 64.0
to 80.7 atomic % with an increase in the Ca/Ni ratio. This heightened presence of interacting NiO was linked
to an enhancement in the DRM process. The authors also suggested that catalyst sintering could be averted by
reinforcing the interaction between the metal and the support, and/or by leveraging the confinement effect of
the support within the material matrix. Another study presented by Xu et al.[99] involved the synthesis of a
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 12/47

three-dimensional Ni/CaO network through a precipitation-combustion method. The remarkable outcomes

demonstrated that this intricate network architecture, featuring both mesoropores and macropores, effectively
restrained the growth and coalescence of CaO particles. In a separated avenue, Zhu et al.[100] proposed the
oxygen vacancy strategy for enhancing CO2 methanation in nickel-based catalysts. They prepared a Y2O3-
promoted NiO-CeO2 catalyst with exceptional methanation activity, which is three times greater than NiO-
CeO2 and six times greater than NiO-Y2O3, particularly at mild reaction temperatures (<300 ℃).
Fe-based catalysts have also demonstrated favourable performance in the DRM process, offering cost-
effective alternatives. For instance, Zhao et al.[101] introduced a Ca-Fe chemical looping reforming method for
DRM. The study revealed a sequence of reactions involving CH4, CaCO3, and Fe2O3. Initially, a swift and
complete CH4 oxidation reaction took place, leading to the conversion of all Fe2O3 into Fe3O4 without
generating CO. Subsequently, the interaction between Fe-based oxygen storage materials and CO2 adsorbents,
coupled with the reforming of CaCO3, facilitated the production of pure syngas. During this stage, Fe3O4
gradually transformed into Fe and FeAl2O4, with concurrent changes in grain size. A recent investigation
introduced an innovative ICCU process utilizing environmentally friendly and cost-efficient CaCO3-derived
CaO, serving as both an effective adsorbent and a highly efficient catalyst for producing high-purity syngas[102].
The findings indicated that the improved DRM process yielded a lower cost of $292/ton for producing CO, in
contrast to the reference scenario’s cost of $447/ton.
In the context of DRM, elevated temperatures (>500 ℃) are imperative to drive reactions. This makes
both CaO and Ni suitable and economically viable. The reaction duration plays a critical role in controlling
coke formation during DFMs and optimizing the H2/CO ratio of syngas in DRM process. The challenge of
sintering, leading to a decline in catalytic activity due to site coverage and metal agglomeration, is significant
at high temperatures. Additionally, the generation of environmentally undesirable CO from coke in DFM
during the adsorption step merits attention.

2.6. Direct air capture technologies

Direct air capture (DAC) aims to extract carbon dioxide from the atmosphere and generate a concentrated
stream of the gas, with the ultimate objective of enabling scalable CO2 storage as a means of positive climate
intervention. Given the broad definition of DAC, numerous promising and evolving methods for
accomplishing this goal are currently being explored[5,25,26].
Regarding development, the liquid solvent and solid sorbent direct air capture (DAC) processes have
made significant progress and will receive more comprehensive discussion in the subsequent section[25].
Nevertheless, there exist several alternative pathways to DAC that have not advanced as extensively in their
development. Cryogenic DAC involves utilizing the sublimation point of CO2 to generate solid CO2 from
ambient air, which can then be stored or resublimed to yield high-purity gaseous CO2[103]. Moisture or humidity
swing adsorption leverages anionic exchange resins to capture and release CO2, offering the potential to reduce
energy demands but possibly increasing water consumption[104]. Voskian and Hatton[105] propose an electro-
swing process where a composite of polyanthraquinone and carbon nanotubes binds to CO2 upon charging and
releases it during discharge, creating a high-purity CO2 stream without the need for thermal energy. Other
strategies involve intentionally produced alkaline feedstock like caustic calcined magnesia (MgO) to capture
CO2 from the atmosphere[106], as well as using an aqueous amino acid solution to absorb CO2 and regenerate it
through crystallization of an insoluble carbonate salt with a guanidine compound[107]. While each of these
techniques presents distinctive avenues for innovation in DAC, the solid sorbent and liquid solvent approaches
stand out as the most advanced and promising in terms of scalability[27].
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 13/47

2.6.1. Liquid sorbent in existing DAC technology

Carbon engineering is committed to the development of liquid-based DAC absorbents. Figure 8 shows
that DAC demonstrations of carbon engineering, which have utilized aqueous solutions of alkali hydroxides.
This liquid base DAC technology comprises of two loops, the contactor loop and the calciner loop[108]. The
contactor loop involves forcing air horizontally through a series of long air contactor units, the first stage
involves the reaction of CO2 with an alkali hydroxide solution in an air contactor, resulting in the formation of
a solution containing alkali carbonate species. Subsequently, this solution is introduced to Ca(OH)2 within
pellet reactors, initiating the creation of a carbonate precipitate. These generated CaCO3 pellets undergo drying
and are subsequently introduced into the calciner. In this chamber, they are subjected to a decomposition
reaction at 900 ℃, yielding CaO, water, and CO2. Currently, the desired temperature in the calciner is achieved
through the use of natural gas and oxygen, resulting in a gaseous mixture mainly composed of CO2 and water.
The CaO is further hydrated in a slaking unit to form Ca(OH)2, which is then reintroduced into the pellet
reactors for the anionic exchange process[27].

Figure 8. DAC process diagram for the solvent process. Reproduced with permission from Bui et al.[76].

In order to address the issue of toxic emissions from amine solutions, researchers have explored the use
of aqueous amino acids for direct air capture (DAC) due to their non-volatile and environmentally benign
nature. This technique utilizing amino acids revolves around the crystallization of a guanidinium carbonate
salt characterized by low aqueous solubility. This process involves the regeneration of the amino acid sorbent
(guanidine) and the subsequent release of CO2 upon heating. Given the endothermic nature of this phase,
concentrated solar power has been employed as an energy source, with the aim of bolstering the process’s
sustainability[106,107].

2.6.2. Solid sorbent in existing DAC technology

Climeworks have developed a series of solid sorbents and they are widely employed in their DAC
plants[27]. These solid sorbents are amine-grafted mesoporous silica. Much of this prior work has focused on
the use of poly(ethylenimine) (PEI) on mesoporous silica, owing to PEI’s high amine content and widespread
commercial availability. Replacing PEI with poly(propylenimine) (PPI) on mesoporous silica has been found
to enhance capacity and improve resistance to oxidative degradation[103].
The tuneable chemistry of metal-organic frameworks (MOFs), both in terms of their framework and post-
synthetic modification, makes them attractive for gas separation applications. However, in DAC process, they
must exhibit moisture durability, which is not a typical characteristic of MOFs, and be amenable to amine
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 14/47

functionalization. One kinds of MOF that has been extensively studied in this context is MIL-101(Cr), which
is known for its water stability and multiple options for amine functionalization[109]. Nevertheless, a balance
must be struck between low CO2 uptake with low amine loading and high CO2 uptake with poor kinetics
resulting from pore blockage or loss of amines at high-amine loading[110]. Recently, a novel core-shell structure
MOFs have been proposed to use in DAC. MOFs-UIO-66 and MOFs-UIO-67 are proven effective DAC solid
sorbents[111].

2.6.3. Economic assessments for DAC technology

At present, DAC technology has begun to be put into practical application. According to previous
report[110], the 19 DAC plants currently operational are able to capture almost 10,000 tonnes CO2 annually.
These DAC facilities are increasing their carbon capture capacity and expanding their operations globally.
Providing a specific cost for DAC technology is difficult due to its early stages, resulting in high costs being a
significant challenge. Specifically, it has been observed that the sorbent DAC process has heat energy needs
close to 6 GJ/ton CO2 and electricity requirements close to 1.5 GJ/ton CO2[27,112].
Comparatively, other carbon capture technologies have varying costs, depending on the limiting factors.
For instance, BECCS has a price range of $20–100/ton CO2, which is lower than DAC’s current cost, always
above $100/ton CO2[110]. However, DAC has more promise due to its limiting factors being related to high
costs, minimal fundamental understanding, and issues for scaling. DAC’s commercial companies, such as
Climeworks and Carbon Engineering, report capture costs of $600/ton CO2 and $94–232/ton CO2, respectively,
which are considered high due to the technology being new[27,110]. Experts have projected a hopeful capture
cost of $100–200/ton CO2, and possibly below $60/ton CO2 by 2040 or 2050, assuming the technology
continues to scale[113]. Fluctuations in costs can be attributed to several factors, including capital costs,
operating costs, and the choice of sorbent used in the system, which can affect the required land area and
energy needed. Table 6 presents a list of significant DAC plants that are currently operational.

Table 6. The working statues of current DAC plants.

Company Plant type Location Sorbent type CO2 removal Operational date
ability
Carbon Engineering[110] Under construction Texas (USA) Liquid absorbent 1million tons/year 2022–2023
Under construction California (USA) Liquid absorbent 1500 tons/year 2022
Climeworks[5,110] Operational Iceland Solid absorbent 4000 tons/year 2021
Operational Switzerland Solid absorbent 900 tons/year 2017
Operational All Europe Solid absorbent 2000 tons/year 2015–2020
Infinitree[89] Operational New York(USA) Ion exchange 100 tons/year 2014–2018
material
Global Thermostat[89] Under construction Oklahoma (USA) Solid absorbent 2000 tons/year 2023
Planning Chile - 0.25 tons/h 2023–2024

2.7. Comparison of various carbon capture techniques

In this section, we reviewed the progress of CO2 capture technologies from 2015 to 2022. In addition to
CO2 capture using industrial flue gas as a carbon source, DAC technology using air as a carbon source has also
been reviewed. There are other CO2 capture technologies, such as bioenergy with carbon capture and storage
(BECCS), clathrate hydrate process, and cryogenic carbon capture that have not been thoroughly summarized
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 15/47

and reviewed in detail. This is partly because they are still in the early stages of development and also due to
limitations in space[67,114].
To conclude this section, even though pre-combustion, oxygen-fuel combustion and chemical cycle
combustion each have their own benefits, it is unlikely that these methods will replace post-combustion capture
in the near future. This is based on the fact that post-combustion capture offers the clear benefit of allowing
current combustion technology to be utilized without the need for significant modifications, making it simpler
to implement in plants that are already in operation[21]. There are also large-scale CCS facilities in operation
by post-combustion methods. The pre-combustion technique is mainly combined with integrated gasification
combined cycle technology (IGCC), but it needs a substantial auxiliary system for optimal functioning.
Therefore, this system’s capital costs are high in comparison to other techniques used for this purpose.
Regarding the oxy-fuel combustion and CLC process, although these technologies have the benefits of
reducing equipment size, compatibility with a variety of fuel types, and low energy penalty, their research is
still at the beginning stages and has not yet been applied to the industrial scale. In 2017, the 50 MW pilot scale
power plant was constructed by Net Power in Texas by using oxy-fuel combustion process[115], which
demonstrates a net zero emission in the concept of carbon capture. Techno-economic assessment of these
processes was performed by Zhu et al.[116], have found that the CLC process displayed a higher energy
efficiency of 39.78% compared to physical absorption (36.21%) and calcium looping (37.72%). The estimated
payback period for these three capture processes was 13.45 years for CLC, 13.21 years for physical absorption,
and 17.25 years for calcium looping.
The benefits and drawbacks of CO2 capture expenses across various technologies are outlined in Table
7. It’s crucial to acknowledge that the cost of CO2 capture is contingent on several factors, including the origin
of CO2 emissions and the extent of the capture initiative. Typically, the cost of CO2 capture constitutes only a
portion of the comprehensive expenses associated with carbon capture and storage (CCS), encompassing the
costs of transporting and storing the captured CO2. The overall expense of CCS can significantly fluctuate
based on the unique nature of the project and the regulatory context.

Table 7. The advantages and disadvantages of various CO2 capture technologies.

Combustion technology Advantages Disadvantages
Pre-combustion 1. Can produce useful and clean hydrogen fuel. 1. High efficiency drops and energy
2. High CO2 concentration contributes to the separation penalty in water-gas shift section.
efficiency. 2. Insufficient experience due to few
gasification plants in actual
application.
Oxy-fuel combustion 1. High concentration at the flue gas exit for simple 1. Cryogenic O2 production is costly
separation. and energy intensive.
2. Significant reduction in NOx emissions from the 2. Corrosion problems maybe arise.
combustion process. 3. The high concentrations of oxygen
3. There are advanced air separation technologies. used are prone to be dangerous.
4. Lower equipment and operating cost are needed, and
there is less flue gas that has to be treated.
Post-combustion 1. More mature technology and enrich industrial 1. Low-concentration and pressure of
experience. the CO2 in the outlet flue gas, which is
2. Easier to retrofit existing plants. not beneficial for absorption.
Chemical looping 1. The combustion products mainly consist of water and 1. Insufficient experience since no
CO2, so it is easy to separate CO2 using simple separation large-scale operation experience.
device.
2. Reaction takes place at medium temperature and remains
unmixed with N2, so no toxic gases such as NOx will be
produced.
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 16/47

Table 7. (Continued).
Combustion technology Advantages Disadvantages
Calcium looping technology 1. CaL can achieve high capture efficiencies of up to 90% 1. The repeated cycles of calcination
or more. and carbonation that occur during
2. CaL requires relatively low energy input compared to calcium looping can cause the calcium
other carbon capture technologies. oxide to decay or degrade over time.
3. CaL can utilize low-grade and waste heat sources to 2. CaL require significant amounts of
regenerate the calcium oxide, which could reduce the land to accommodate the large
overall energy. equipment and infrastructure required
for the process.

3. Post-combustion: Process and technologies

As mentioned in Section 2.5., currently, the most significant technology to upgrade conventional fossil
fuel power plants is the post-combustion capture (PCC), which can be retrofitted to existing power plants with
minor modification. However, PCC technology requires a substantial investment in terms of reactive solvents
and other equipment, which may raise the cost of power generation by around 70%[117]. Therefore, scientist
has devoted their research efforts on finding superior solvents that are less energy-intensive and inexpensive.
In this section, the current progress of PCC technologies in terms of advanced solvent formulations, process
configuration, and superior solvents is comprehensively summarized and reviewed.
Various CO2 separation technologies are available for post-combustion capture, such as (a) physical
absorption; (b) chemical absorption; (c) adsorption; (d) cryogenics; and (e) membrane separation (Figure 9).
Other methods, such as biochemical methods involving the biological fixation and microbial immobilization
are less practiced to date, and not considered in this present review. The selection of the appropriate technology
is determined by the characteristics of the flue gas stream, such as temperature, pressure, and CO2
concentration and some other factors, such as purity of the target CO2 product, sensitivity to impurities, and
the environmental impacts.

Figure 9. Technology options for CO2 separation. Reproduced with permission from Olajire et al.[61].

Among these, absorption of CO2 by liquid solvents is the most advanced technique, due to it is been
thoroughly tested, has significant processing capacity, and extensive industrial operating data is available. It is
advantageous to deal with significant large combustion emissions, and it has useful applications in a variety of
sectors, including flue gas purification, biogas upgradation, and processing of natural gases[118]. Physical
absorption and chemical absorption are the two subcategories of liquid absorption. When the absorption
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 17/47

process solely involves the mass transfer of gas molecules between the gas and liquid phases, physical
absorption is contingent on the gas’s solubility and the operating circumstances. Chemical absorption happens
when a reaction occurs between the gas being absorbed and the existing solute in the solution. Chemical
absorption enhances selectivity and separation efficiency compared to physical absorption[119].

3.1. Physical absorption

Physical absorption uses organic solvents to physically dissolve the acidic gas instead of performing a
chemical reaction. The driving force for CO2 absorption by physical absorbents is solubility, which varies in
different solvents, and the solubility also heavily relies on the partial pressure and temperature of CO2. Henry’s
law states that a lower temperature and higher partial pressure make CO2 easier to dissolve in organic
solvents[61].
The advantage of using the physical absorption method is that the association bond between the physical
absorbent and CO2 is weaker than in chemical absorption process. It reduces the amount of energy needed for
regeneration and simplifies the regeneration process which consists of only a gas-liquid contactor and several
flash drums (Figure 10). As the physical solvent is a non-corrosive absorbent, expensive alloy steel is not
required for piping and plants, thus reducing the capital investment[120]. However, physical absorption relies
on the pressure of CO2 and generally taken into account when the partial pressure of CO2 is more than 3.5
bar[1]. Moreover, it is not economical to apply physical absorption in flue gases where the partial pressure of
CO2 is less than 0.15 bar, since high energy is required to pressurize the flue gas[10].

Figure 10. Process flowsheet of physical absorption process. Reproduced with permission from Olajire et al.[61].

There are several existing industrial methods for physical liquid absorption, such as Fluor (Propylene
carbonate), Rectisol (Methanol), Estasolvan (Tributyl phosphate), Purisol (Normal methyl pyrrolidone or
NMP), and Selexol (Dimethyl ether of polyethylene glycol)[43,61]. Among these, Selexol (Dimethyl ether of
polyethylene glycol) and Rectisol (Methanol) are the most common and already used on a commercial scale.
Kapetaki et al.[121] investigated a dual-stage Selexol process for higher degree of CO2 removal and found that,
for 95% carbon capture, the Selexol process requires 65% more energy than in the 90% capture case. Reducing
the size of equipment and energy penalty have been the primary goals of research in physical absorption
technique. Therefore, latest research on physical absorption includes reducing energy demands by developing
new solvents, refining the process configuration design, and developing mathematical models of mass transfer
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 18/47

rates, to optimize the thermal and economical aspects of this process[122]. Table 8 summarizes the latest
research on physical absorbents and details the benefits and drawbacks of a variety of physical solvents.

Table 8. Recent research progress of physical-absorption technologies.

Ref Solvents Abstract of techniques
[123] DEPG A two stage Selexol process simulation was deeply investigated, the energy needed to capture 95% of
CO2 is 65% more than the energy required to capture 90% of CO2.
[124] Dual-stage Selexol process was simulated in the IGCC system for eliminating CO2 as well as H2S.
The authors demonstrate that by modifying the operating parameters, a typical, integrated dual-stage
Selexol device may achieve 95% CO2 collection.
[125] The economic feasibility of the Selexol process was improved by incorporating dimethyl carbonate
(DMC), diethylcarbonate (DEC), and triacetin (TAT) into the DEPG solution.
[126] Methanol The single-stage and two-stage Rectisol procedures were both evaluated, taking into account factors
such as the efficiency of gas removal, heat recovery, equipment needs, energy consumption, and costs.
[127] Simultaneous optimization of the energy penalty and CO2 capture rate in the Rectisol process was
performed to determine the optimal operating parameters.
[128] Predicting the thermodynamics behavior of Rectisol process by using SAFT EOS.
[129] Glycerol The performance of CO2 capture increased with temperature and pressure increased.
[37] Ionic liquid The physical absorption of ionic liquid [hmim] [Tf2N] showed a similar energy consumption as
[hmim] [Tf2N] Selexol process.

3.2. Chemical absorption

Chemical absorption is most widely used method for CO2 capture because of a higher CO2 selectivity and
faster absorption kinetics. Unlike physical absorption, chemical absorption is favourable even when the CO2
partial pressure is low. Since CO2 is an acidic gas, removing it from a gaseous stream using chemical absorption
is based on acid-base neutralisation reactions using an alkaline solution. This process is also known as the
electrophilic reaction of CO2, which is determined by its molecular structure. As the oxygen atom is more
electronegative than the carbon atom, it causes the electrons on the carbon atom to be shifted away, thus making
the carbon atom on CO2 electron deficient. The electron-deficient CO2 is easily attacked by the electron-rich
group of an amine that contains nitrogen and oxygen atoms, ultimately creating a chemical bond[130].
The intermediate compounds are formed by a weak bond between absorbent and CO2, and these bonds
are then broken by providing thermal energy to obtain pure stream of CO2. However, this approach also has a
number of drawbacks, including high corrosivity, high energy consumption during solvent regeneration, a
rapid rate of solvent degradation, and evaporation of solvents. These drawbacks are the main obstacles to the
wide application of chemical absorption in large industrial emission sources.
To address these challenges, many types of chemical absorbents have been developed, such as
alkanolamine solutions, carbonate solutions, water ammonia solutions, double alkali absorbents, and cold
ammonia absorbents[61]. Among these, CO2 absorption by alkanolamine solutions gained unmatchable interest
due to their strong CO2 affinity.
A representative configuration of the chemical absorption method is depicted in Figure 11. Within the
absorber column, flue gas is introduced from the bottom, coming into contact with the absorbent descending
from the top. The solvent assimilates the CO2 and exits the absorber through its lower section. This CO2-
enriched solvent is conveyed to a stripper column, where thermal energy is supplied to regenerate the amine.
This thermal treatment disrupts the chemical bonds between CO2 and the absorbent. The CO2 liberated during
this process enters the condenser, which serves to separate the vaporized absorbent and water from the CO2.
The resultant high-purity CO2 is then pressurized and conveyed for the subsequent phase. Subsequently, the
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 19/47

regenerated solvent undergoes cooling and is cycled back to the absorber column for the ensuing absorption
cycle. The operational parameters governing the absorber and stripper, such as temperature and pressure,
typically fluctuate based on the chosen chemical absorbent.

Figure 11. Typical configuration for CO2 chemical absorption. Reproduced with permission from Chao et al.[22].

3.2.1. Amine-based chemical absorption

Aqueous amine solutions have been used in industry for decades as the most common method of
chemically CO2 scrubbing because the amine reacts to CO2 quickly, with high selectivity, and weak bonds are
formed during absorption reaction. The weak bond can be destroyed by heating, leading to regeneration of the
amine absorbent. Amines usually contain amino groups and hydroxyl groups. The presence of the amino group
enhances the alkalinity of the aqueous solution, enabling the effective absorption of acidic gas components.
The hydroxyl group reduces the compound’s vapor pressure and enhances its water solubility.
Alkanolamines can be classified as straight-chain and cyclic organic amines based on their molecular
structure. Straight-chain organic amines are categorized as primary, secondary, or tertiary based on how many
hydrogen atoms are linked to the amino nitrogen atom. For both primary and secondary amines, the nitrogen
atom on the amino group attacks the carbon atom of the CO2 molecule to produce zwitterion. It is a charge-
separated resonant form of isomeric carbamic acid. The carbamic acid that is formed is structurally unstable.
Thus, it readily loses its proton to another molecule of free amine, leading to the formation of the more stable
ammonium carbamate[130]. The stoichiometric coefficient for reaction (Equation (5)) indicates that two moles
of amine and one mole of CO2 will react, resulting in a theoretical maximum CO2 loading of primary and
secondary amine of 0.5 mole CO2 per mole amine.
퐶푂� + 2푅푁퐻� ↔ 푅푁퐻퐶푂푂� + 푅푁퐻�� (5)

Tertiary amines lack hydrogen atoms linked to their nitrogen atoms. Hence, the generated zwitterions
cannot be converted to carbamic acid by intramolecular proton transfer, nor can they undergo the deprotonation
process. Therefore, they cannot produce stable ammonium carbamates with CO2[130]. Instead, the tertiary amine
can react with CO2 indirectly through a base-catalysed hydration reaction (Equation (6)) involving water to
produce bicarbonates. According to the chemical reaction formula, each mole of tertiary amine can react with
one mole of CO2. Compared to primary and secondary amines, tertiary amines have a theoretical maximum
loading of 1[131].
퐶푂� + 푅� 푅� 푅� 푁 + 퐻� 푂 ↔ 푅� 푅� 푅� 푁퐻 � + 퐻퐶푂�� (6)
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 20/47

Typically, the reaction rate for reaction (4) is faster than that of reaction (5). However, the rate of reaction
also depends on the extent to which the reaction proceeds and the solution’s viscosity. Several types of amines
have been subject to investigation by researchers, including primary monoethanolamine (MEA), secondary
diethanolamine (DEA), tertiary N-methyldiethanolamine (MDEA), cyclic piperazine (PZ), and the sterically
hindered 2-amino-2-methyl-2-propanol (AMP). CO2 absorption using amine solutions such as
monoethanolamine (MEA) is a technology that has been applied commercially to the field of natural gas
industry for 60 years[61]. The 30 wt% aqueous MEA is always seen as the benchmark amine absorbent. MEA
is especially suitable for applications with low partial pressures of CO2. However, the main drawback of
aqueous MEA process is the high energy penalty during amine regeneration, which accordingly reduces the
power plant efficiency. The estimated efficiency are in the range of 36%–42% for retrofitting an amine based
CO2 capture unit to existing plants and between 25%–28% for application to new plants[132]. Research efforts
to reduce energy consumption include improving the operating temperature of the stripper column[133], using
catalyst-assisted regeneration, and using novel energy-efficient absorbents. In addition, the aqueous MEA
solution itself is highly corrosive to the reaction equipment and transport pipelines[134].
The absorbent plays a crucial role in the chemical absorption process. An ideal absorbent for CO2 capture
should possess several key attributes, such as a fast absorption rate, ample absorption and desorption capacity,
low energy consumption during regeneration, thermal stability, nontoxicity, low corrosiveness to equipment,
and economical feasibility[135]. In this regard, substantial work has gone into the development of absorbents.
The amine-based absorbents are by far the most common materials in the CCS industry. The amine absorbents
explored to date can be broadly divided into four categories: single amine absorbents, blended amine
absorbents, bi-phasic absorbents, and non-aqueous absorbents[136].
Single amine absorbent
Single amines have been the most thoroughly investigated solvents in chemical absorption for CO2
capture. Main categories of single amines are primary amines, secondary amines, tertiary amines, cyclic
amines, and sterically-hindered amines[43]. The most commonly used representative from each category of
single amine absorbents is thoroughly discussed below.
Monoethanolamine (MEA) is a primary amine first used by Bottoms in 1930 to separate acidic gases[137].
It has been regarded as the benchmark of the CO2 separation process due to its high water solubility, low
viscosity, cheap price and high reactivity with CO2[137]. However, the major drawbacks of the aqueous MEA
absorber are the high corrosion rate and the high regeneration energy of approximately 3.3–4.4 GJ/ton CO2[138].
Diethanolamine (DEA) is a secondary amine which has similar structure as MEA. Compared to
conventional MEA process, the DEA process have around 4.5% energy saving under same CO2 capture
condition[139]. Generally, DEA is always used as an activator or additive to make blended amine absorbents,
such as DEA/AEEA absorbent, MDEA/DEA absorbent and DEA/MEA absorbent[140–142].
Methyl-diethanolamine (MDEA) is a typical tertiary amine and has been widely used in gas purification
since 1980[143]. Because of the lack of active hydrogen atoms on the amino nitrogen atom, the stability of
MDEA cause less susceptible to solvent degradation and less foamy and corrosive than MEA. The absorption
capacity of CO2 in the MDEA-H2O-CO2 system was studied at temperatures ranging from 313 K to 393 K,
with MDEA concentrations as high as 50 wt%, and CO2 loadings reaching up to 1.32[144]. However, the
disadvantage is that MDEA can only react with CO2 in aqueous solutions under a low reaction rate.
Due to their unique cyclic diamine structure, cyclic amines such as piperazine and its derivatives have
fast reaction rates with CO2 and high absorption capacity. The presence of two amine groups increases the
reaction site with CO2 and the proton acceptance probability, resulting in the formation of carbamates and
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 21/47

catalysing the formation of bicarbonates. The CO2 uptake rate and capacity of 40 wt% PZ are twice as high as
that of the 30 wt% monoethanolamine (MEA) reference solvent. Therefore, piperazine (PZ) has been proposed
as a second-generation amine absorbent after MEA washing[145].
Sterically-hindered amines (e.g., 2-Amino-2-methyl-1-propanol (AMP) and its derivatives) were
proposed by Sartori and Savage[146]. AMP is a primary amine with a similar molecular structure to MEA but
with two additional methyl groups attached to the amine group’s carbon atoms, providing a steric hindrance
effect and reducing the reaction product’s stability. This effect allows for easier regeneration of the amine. The
formation of bicarbonate in sterically-hindered amine aqueous solution gives a larger theoretical absorption
capacity of 1 mol-CO2/mol-amine loading, which is twice that of the unhindered primary amine. Sun et al.[147]
analyzed and simulated the AMP process and found that, compared to conventional MEA process, the energy
consumption of AMP process is 19% less, while the CO2 removal efficiency was also increased from 88% to
93%. Moreover, pilot-scale experiments showed that the regeneration of AMP was 41.7% less energy intensive
than MEA. Chakraborty et al.[148] explained this phenomenon based on molecular orbital justification. They
claimed that the negative charge of the amine nitrogen atom of the AMP molecule is reduced by 3.4%
compared to that of the MEA molecule because of the dimethyl a-substituent. This leads to weaker basicity of
AMP and weakens the stability of AMP’s binding bonds to CO2.
Blended amine absorbents
Using single-amine solutions have hampered their further application as CO2 absorbents. Aiming to
compensate for the disadvantages of single amine solutions and exploit their respective advantages,
Chakravarty et al.[148] first introduced the concept of mixing amine solutions of different properties to prepare
blended amine solutions. These blended amine absorbents display great absorption efficiency and require less
energy for regeneration.
Generally, the amine mixtures consist of a primary or secondary amine with a tertiary or sterically
hindered amine. These amine mixtures combine the high reactivity of primary and secondary amines with the
high absorption capacity of tertiary and sterically hindered amines[149]. In addition, PZ is often used as it has
been reported to be used as a substitute for MEA and DEA to substantially increase the absorption rate of
mixed amine solutions[147]. Typically, there are two ways of mixing blended amine absorbents. One is to use a
primary or secondary amine with fast reaction kinetics as the mainstay and gradually add tertiary or sterically
hindered amines to decrease energy consumption. The other way is to add an activator (primary amines or
cyclic amines) to the tertiary or sterically hindered amines to improve the absorption rate. Both ways require
the selection of the appropriate amine and optimization of the concentration of each amine (i.e., the mixing
ratio).
The blended amine absorbents could accelerate the reaction of CO2 with amine molecules. Because the
interaction between primary and tertiary amine molecules takes place via a termolecular reaction
mechanism[150]. Chen et al.[151] investigated that tertiary amines could react as bases with equimolar molecules
of MEA and CO2 via termolecular reaction mechanism. In other words, the tertiary amine molecule could
restore the protonated MEA to a free molecule. A large number of free MEA molecules in solution increased
the CO2 absorption rate.
Adding the activator PZ to MDEA or AMP absorbents not only increases the amine solution’s absorption
rate but also addresses the precipitation of PZ solids[152]. The mixture of PZ and AMP is a well-known novel
blended amine absorbent. Seo et al.[153] first investigated the mixing of PZ as a reaction activator into an
aqueous AMP solution. Their experimental results showed that the addition of PZ greatly increased the reaction
rate. Later, Yang et al.[154] found that the mixed amine solution of PZ and AMP had a fast absorption rate and
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 22/47

high absorption capacity. Moreover, the regeneration energy consumption was about 80% of the conventional
MEA absorbents. In contrast to the precipitation problems associated with employing PZ as an activator, MEA
does not form precipitates. Recent studies have shown that MDEA absorbers activated with MEA have mass
transfer rates close to those of aqueous MEA solutions and have higher absorption than MDEA at lower partial
pressures of CO2[155]. The regeneration energy is reduced by 6%–12% compared to the conventional MEA
aqueous solution[41]. Improved MDEA/PZ blended absorbents was demonstrated for a 650 MW power plant
by Zhao et al.[156]. The reboiler duty in this process was 2.24 GJ/ton, which is 42% lower than the conventional
MEA process.
Additionally, blended absorbents consisting of more than two different amines have also received
attention recently. Zhang et al.[157] investigated the carbon capture energy consumption of MEA/MDEA/PZ
amine absorbents with different composition ratios. They discovered that energy penalty can be decreased by
15.22%–49.22% depending on the mixing ratio. Nwaoha et al.[158] compared a ternary amine absorbent
consisting of AMP/MDEA/DETA with an MEA absorbent and found that the cyclic loading and cyclic
capacity of the ternary amine absorbent increased by more than 100% compared to the MEA absorbent, while
the regeneration energy consumption was reduced by more than 50%. They also investigated the performance
of AMP-PZ-MEA amine sorbents in blends. They found that this ternary solvent absorbent had a greater
recyclability and lower regeneration energy consumption (around 50%) than the 5 molar MEA solution[149].
MEA/MDEA absorbents and MEA/MDEA/AMP absorbents were evaluated by Liu et al.[159], and it was found
that, compared to the conventional MEA process, the regeneration efficiency of MEA/MDEA/AMP absorbents
increased from 24% to 51% in twenty minutes desorption stage. A summary of recent research on single and
blended absorbents is presented in Table 9.

Table 9. Recent research of CO2 absorption performance of aqueous amine absorbents.

Ref Device Temperature CO2 loading Concentration Energy Absorbents
consumption
[160] Bench-scale unit 313 K 0.429 mol/mol 5 M/2 M - MEA/MDEA/Al2O3
[160] Bench-scale unit 313 K 0.432 mol/mol 5 M/2 M - MEA/MDEA/H-ZSM-5
[161] Stirred reactor 318 K 0.885 mol/mol 10 wt%/5 wt%/0.05 - MDEA/PZ/nMWCNT
wt%
[161] Stirred reactor 318 K 0.738 mol/mol 10 wt%/5 wt%/0.05 - MDEA/MEA/nMWCNT
wt%
[162] Stirred reactor 298 K 0.54 mol/mol 20 wt%/2 wt% Around 3.2 GJ/ton MEA/TiO(OH)2/H2O
[163] Jacket reactor 308 K 0.7 mol/mol 4.5 wt%/0.5 wt% MDEA/PZ/H2O
[164] Stirred reactor 308 K 98.76% 30 wt% - AMP/PZ/H2O
[165] Stirred reactor 293–323 K 0.5 mol/mol 30 wt% 2573 GJ/ton MEA/H2O

[165] Stirred reactor 293–323 K 0.91 mol/mol 30 wt% 1823 GJ/ton MEA/EG/H2O

[166] Stirred reactor 298–313K 0.49–0.67 23.5 wt% - MDEA/H2O

mol/mol
[166] Stirred reactor 298–313 K 0.25–0.38 28.7 wt% - TEA/H2O
mol/mol
[166] Stirred reactor 298–313 K 0.79–0.85 23.6 wt% - DEEA/H2O
mol/mol
[167] Bench-scale unit 313 K 0.536 mol/mol 3.35 mol/L 3.74 GJ/ton AMP/H2O
[167] Bench-scale unit 313 K 0.533 mol/mol 3.03 mol/L 3.76 GJ/ton DEA/H2O
[167] Bench-scale unit 313 K 0.487 mol/mol 5 mol/L 4.01 GJ/ton MEA/H2O
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 23/47

Table 9. (Continued).

Ref Device Temperature CO2 loading Concentration Energy Absorbents

consumption
[168] Stirred reactor 313 K 0.41 mol/mol 30 wt% 2.13 GJ/ton MDEA/H2O
[45] Parallel glass 313.15 K 1.35 mol/mol 30 wt% −98.39 Kj/mol * Hexamethylenediamine/H2
reactors O
[45] Parallel glass 313.15 K 0.83 mol/mol 30 wt% −87.17 Kj/mol * Diethyamine/H2O
reactors
[45] Parallel glass 313.15 K 1.03 mol/mol 30 wt% −97.23 Kj/mol * 1,3-diaminopropane/H2O
reactors
[169] Stirred reactor 303–323 K 0.2–1.2 mol/mol 20 wt%/10 wt% - AEP/MDEA/H2O

[170] Stirred reactor 313 K 0.73 mol/mol 3 M/1.5 M −60.97 Kj/mol * DEEA/MAPA
[170] Stirred reactor 313 K 0.87 mol/mol 3 M/2 M −54.35 Kj/mol * DEEA/MAPA
[170] Stirred reactor 313 K 0.84 mol/mol 3 M/3 M −57.55 Kj/mol * DEEA/MAPA
[170] Stirred reactor 313 K 0.81 mol/mol 3 M/3.5 M −61.97 Kj/mol * DEEA/MAPA
* Reaction heat of absorbents with CO2.

Biphasic amine absorbents

The biphasic absorbent is referred to as a phase-split absorbent or phase-separation absorbent. Because
the amine solution starts as a single phase and after absorption of CO2 in the absorber, two immiscible phases
formed (liquid-liquid or liquid-solid) due to a change in the polarity of the reaction products[171]. Usually, the
upper liquid layer is the CO2 depleted phase and is separated out before being transported to the stripping
column. Therefore, only the CO2-rich phase is separated and regenerated in the stripper column. Moreover,
the higher content of CO2 in the CO2-rich phase leads to an increase in regeneration efficiency, which allows
for less pump work.
The aqueous biphasic absorbents usually consist of an absorption promoter, a phase separating agent, and
water. Zhang et al.[172] investigated a biphasic mixture containing MEA, 1-propanol, and H2O. They found that
the CO2-enriched solution was within 33% of the total solution, which significantly reduced the volume of
liquid to be regenerated. Another MEA-based biphasic absorbent was studied by Wang et al.[173], and they
found that the regeneration heat consumption of MEA-sulfolane-H2O system was 2.67 GJ/ton CO2, which is
31% lower than the conventional MEA process. The biphasic solvents can reduce regeneration energy
consumption by 30%–50% compared to the conventional MEA process. However, the water content in
biphasic absorbent is an important influencing factor on CO2 capture performance. Water has a high specific
heat capacity and enthalpy of vaporization, which requires a high amount of energy in regeneration. Moreover,
the presence of water also accelerates the corrosion of the equipment[135].
Non-aqueous biphasic absorbents, known as water-lean solvents, find application through various
solvents such as sulfolane for the creation of biphasic absorbents[174–176]. In the context of TETA/DEEA,
sulfolane is employed to modulate phase separation behaviour, resulting in simultaneous volume ratio
reduction and heightened CO2 loading within the rich phase. A comparison between TETA/DEEA/H2O and
TETA/DEEA/Sulfolane showcases a decline in the volume ratio of the rich phase from 83% to 39% and an
increase in CO2 loading within the rich phase from 3.10 to 4.92 mol/L[174,177]. This approach reduces
regeneration heat to 1.81 GJ/ton CO2, indicating a 26.4% reduction compared to DEEA-TETA and a 54.6%
decrease compared to the 30 wt% MEA solution. Furthermore, novel solvents have been introduced to the
phase change absorption technique, employing long-chain alcohols such as 1-Heptanol, 1-octanol, and
isooctanol. In this approach, MEA/alcohols and DEA/alcohols show lower CO2 loadings compared to
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 24/47

MEA/water and DEA/water. During absorption, alcohols (forming the CO2-lean phase) are present in the upper
phase, while amine carbamate (constituting the CO2-rich phase) is situated in the lower phase[178].
Recently, a multi-components non-aqueous biphasic solvent was proposed by Li et al.[179] that consists of
MEA, AMP, dimethylsulfoxide (DMSO) and N,N,N′,N″,N″-pentamethyldiethylenetriamine (PMDETA). The
experimental results showed a relative high CO2 capacity of biphasic absorbents, which is 0.88 mol/mol.
Biphasic absorbents are advantageous in terms of absorption capacity, cycle capacity, and regeneration energy.
However, the high viscosity of CO2-enriched fluids is a significant barrier to its application, as it reduces the
efficiency of mass and heat transfer[135,172,180]. The details of recent research on biphasic absorbents are
summarized in Table 10.

Table 10. Recent research of CO2 absorption performance of biphasic amine absorbents.
Ref Device Temperature CO2 loading Concentration Energy consumption Absorbents
[181] Stirred cell 303 K 2.51 mol/kg 30 wt% 2.4 MJ/kg MEA/1-propanol (phase-
reactor changed)
[182] Stirred cell 298 K 1.48 30 wt% 2.12 MJ/kg DETA/1-propanol (phase-
reactor changed)
[173] Stirred cell 318 K 3.88 mol/L 4 M/5 M 2.67 MJ/kg MEA/Sulfolane (phase-
reactor changed)
[180] Stirred cell 313 K 0.98 4M 1.83 MJ/kg TETA/TMBDA/DEGMEEb
reactor (phase-changed)
[180] Stirred cell 303 K 4.92 mol/L nDEEA:nTETA = 4:1 1.81 MJ/kg DEEA/TETA/Sulfolane
reactor (phase-changed)
[180] Stirred cell 303 K 3.1 mol/L nDEEA:nTETA = 4:1 2.3 MJ/kg DEEA/TETA/H2O (phase-
reactor changed)
[183] Stirred cell 333 K 1.78 NAEEA:NDMSO = 4:6 1.76 MJ/kg CO2 AEEA/PMDETA/DMSO
reactor (phase-changed)
[183] Stirred cell 333 K 1.77 NAEEA:NDMSO = 5:5 1.69 MJ/kg CO2 AEEA/PMDETA/DMSO
reactor (phase-changed)

[184] Stirred cell 293 K 0.82 0.2 mol/L - PZ/DMF (phase-changed)

reactor
[185] Stirred cell 323 K 0.85 NAMP:nTETA = 2:1 - TETA/AMP/NMF (phase-
reactor VNMF = 70% changed)

Non-aqueous amine absorbents

As mentioned earlier, massive energy penalty of amine regeneration is one of the major drawbacks of
absorption-based CO2 capture. The energy consumed for absorbent regeneration can be divided into three parts:
(i) the sensible heat (Qsen) that is the heat consumed to raise the temperature of amine solution; (ii) the
desorption reaction heat (Qdes) which is the energy to break the chemical bond between the CO2 and the amine;
and (iii) the heat of vaporization (Qlatent) that is the heat consumed to vaporize water[186,187]. Among these, the
desorption reaction heat (Qdes) depends on amine types, while the sensible heat and latent heat mainly depend
on the water content in the solvent as water is used as a co-solvent in aqueous amine solutions. Due to water’s
high specific heat capacity and vaporization enthalpy, in conventional aqueous amine absorbents, around half
of the total provided energy is wasted to heat and vaporize water. Regeneration at high temperatures can
increase the degradation rate of the amine solution and the corrosion of the equipment. As a result, more
researchers are now interested in developing non-aqueous solvents, which they believe will avoid many of the
problems mentioned earlier. So far, most non-aqueous absorbents based on amines have been tested with
organic solvents or room-temperature ionic liquids.
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 25/47

Alcohols, ethers, and glycols are common co-solvents in the non-aqueous absorbents. These solvents
offer a significant advantage in reducing equipment corrosion and amine degradation. Among alcholos,
methanol and ethanol are the most investigated co-solvents. Chen et al.[188] compared EMEA/ethanol with
EMEA/water and found that the absorption of non-aqueous absorbents was less than that of aqueous solutions.
However, the regeneration efficiency was 50% higher than that of the aqueous solution. Liu et al.[189]
investigated TETA and AMP mixed amine absorbents using ethanol as a co-solvent. It was found that this
non-aqueous absorbent exhibited a high absorption capacity (3.71 mol kg−1) and regeneration efficiency
(95.4%). Other non-volatile alcohols such as 1-hexanol and 1-propanol are also thoroughly investigated. The
CO2 absorption performance of MEA/MDEA/1-Hexanal was examined by Ulus et al.[190]. The additive tertiary
amine increased absorption capacity from 0.39 to 0.67 mol CO2 per mol amine with a reasonable absorption
rate. Barbarossa et al.[191] devised a series of AMP-based solutions for chemical CO2 capture. From their results,
the AMP/MMEA/1-propanol mixture had an equilibrium absorption efficiency of 95.9% at 333 K. All AMP-
based blended absorbents had more than 90% equilibrium absorption efficiency at regeneration temperature
of 363 K.
Glycols are also commonly used non-aqueous solvents, including ethylene glycol (EG), triethylene glycol
(TEG), and polyethylene glycol (PEG). The mixture composed of 2-PE and EG showed high CO2 loading
(0.97 mol-CO2/mol-amine), and 2-PE/EG absorbent could be fully regenerated under low temperature (323.15
K)[192]. Zheng et al.[193] studied CO2 solubility in AMP/TEG non-aqueous absorbents, and found that the
AMP/TEG absorbents could consume less energy than the MEA/TEG absorbents. Li et al.[194] investigated
MEA/PEG, DEA/PEG and DGA/PEG absorbents. In particular, a solution of 3 mol/L DGA/PEG exhibited a
high cycling loading of 0.438 mol-CO2/mol-amine with regeneration efficiency up to 94.6%. Another research
about AMP/Glycols absorbent was investigated by Barbarossa et al.[191]. In their study, AMP anhydrous
absorbents were mixed with various alcohol mixtures (EG/Ethanol; EG/1-Propanol). A regeneration efficiency
of 90% was achieved at 80 ℃. The energy consumption of glycol-based non-aqueous absorbents was
investigated by Tian et al.[195]. The regeneration energy of 30 wt% MEA/PEG200 was found to be 2.55 MJ/kg,
which is 33% lower than the conventional aqueous MEA process.
Glycol ethers, due to their low viscosity, are frequently used in the formation of non-aqueous absorbents.
Guo et al.[196] examined the efficacy of MEA in 2-ME and 2-EE glycol ethers. They discovered that the ability
of 30 wt% MEA to absorb in these solvents was comparable to its absorbency in water, and it had a higher
efficiency of regeneration and required approximately 45% less energy than in water. Barzagli et al.[197]
evaluated DEGMME as a solvent for non-aqueous amine absorbents and found that a mixture of DGA and
DEGMME was a viable alternative to aqueous MEA solutions, offering a faster absorption rate and a lower
heat of absorption. Bougie et al.[43] investigated the desorption performance of MEA in DEGMEE by
microwave regeneration. Their results showed that the DEGMEE solution could reduce energy consumption
by 78% compared to the conventional 30 wt% aqueous MEA process. Barzagli et al.[198] tested the continuous
absorption and desorption performance of AMP and AMP-amine mixtures in anhydrous solvents, such as
EG/1-PrOH mixtures or DEGMME. Results showed CO2 removal ranging from 87%–95% at desorption
temperatures of 90–95 ℃.
Room temperature ionic liquids (RTILs) can also be classified as novel non-aqueous solvents. These
solvents are known for their low evaporation pressure, high heat stability, and adjustable physical
characteristics, making them more environmentally friendly than traditional solvents. Research conducted by
Xu et al.[145] showed that the addition of RTILs [C2OHmim][DCA] and [bmim][DCA] to a 30 wt% MEA
aqueous solution could lower energy consumption by 27%. Khan et al.[199] experimentally analysed the
physicochemical properties of another ionic liquid addition CO2 absorbent. The addition of ionic liquids
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 26/47

([bmim][OTf] and [bmim][AC]) to 30 wt% MDEA/3wt% PZ showed a significant increase in the CO2
absorption capacity. At 10 wt% ionic liquid content, the CO2 loading increased from 1.32 to 1.77 for the
[bmim][OTf] solvent and to 1.84 for the [bmim][AC], but these ionic liquids also increased the viscosity of
the absorbent. Yang et al.[200] found that the addition of the hydrophilic ionic liquid [bmim][BF4] to the aqueous
MEA solution can significantly reduce the loss of MEA in the carbon capture process and the regeneration
energy consumption. The regeneration energy consumption of 50% [bmim][BF4] + 30% MEA + 20% water
was found to be 2.38 GJ/ton CO2, which is 33.8% lower compared to the conventional MEA process. Xiao et
al.[201] demonstrated that an ionic liquid solution composed of [bmim][BF4], MEA, and MDEA exhibits
superior regeneration performance and reduced energy consumption compared to aqueous solutions.
For CO2 separation from flue gas, non-aqueous solvents include alcohols such as methanol, ethanol, and
propanol, glycols like EG, DEG, and TEG, and ionic liquids. However, using high-volatility alcohols with
high saturated vapour pressures leads to significant solvent losses and can have negative environmental
impacts. However, the use of glycols as solvents is hindered by their non-linear viscosity increase, which slows
down mass transfer and reduces absorption rate. The high complexity, expensive fabrication materials, and
unknown toxicity of ionic liquids pose additional challenges to their widespread commercial use. The details
of recent research on non-aqueous amine absorbents are summarized in Table 11.

Table 11. Recent research of CO2 absorption performance of non-aqueous amine absorbents.
Ref Device Temperature CO2 loading Concentration Energy Absorbents
consumption
[43] Stirred cell reactor 298 K 0.47 30 wt% 1700 KJ/mol CO2 MEA/EG/PrOH
[43] Stirred cell reactor 298 K 0.50 30 wt% 3630 KJ/mol CO2 MEA/Water
[43] Stirred cell reactor 298 K 0.49 30 wt% - MEA/NMF
[43] Stirred cell reactor 298 K 0.48 30 wt% 929 KJ/mol CO2 MEA/DEGMEE
[195] Stirred cell reactor 313 K 0.483 5 mol/L 2547 KJ/g CO2 MEA/PEG200
[196] Stirred cell reactor 313 K 2.1 mol/kg 30 wt% 5.1 MJ/kg MEA/2-ME
[196] Stirred cell reactor 313 K 2.045 mol/kg 30 wt% 5.0 MJ/kg MEA/2-EE
[196] Stirred cell reactor 313 K 1.662 mol/kg 30 wt% - DEA/2-ME
[196] Stirred cell reactor 313 K 2.198 mol/kg 30 wt% 10.8 MJ/kg MEA/H2O
[202] Stirred cell reactor 333 K 1.74 2 mol/L 39 MJ/kg TETA/EG
[202] Stirred cell reactor 333 K 1.72 2 mol/L 41 MJ/kg TETA/DEG
[202] Stirred cell reactor 333 K 1.86 2 mol/L 25 MJ/kg TETA/PEG200
[203] Stirred cell reactor 303 K 1.82 30 wt% 84 MJ/kg TETA/PEG200
[203] Stirred cell reactor 303 K 1.75 30 wt% 92 MJ/kg TETA/BDO
[192] Stirred cell reactor 298 K 0.97 1:6 - 2-PE/EG
[204] Rotating packed bed 323 K - 40 wt% 33.6 KJ/mol PZ/DEG
[205] Stirred cell reactor 293 K 0.23–0.5 10 wt%–90 wt% 25.49 KJ/mol DMEA/EG
[150] Stopped-flow reactor 298–313 K - 0.2 M MEA 12.19 KJ/mol MEA/DMEA/Ethanol
0.3 M DMEA
[150] Stopped-flow reactor 298–313 K - 0.2 M MEA 14.19 KJ/mol MEA/DEEA/Ethanol
0.3 M DEEA
[198] Stirred cell reactor 293 K 89.1% 3 M AMP - AMP/IPMEA/
EG/PrOH
[198] Stirred cell reactor 293 K 89.1% 3 M AMP - AMP/EG/PrOH
[206] Stirred cell reactor 298 K 1.65 mol/kg 2.5 M AMP 2.09 MJ/kg AMP/AEEA/NMP
0.5 M AEEA
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 27/47

3.2.2. Chilled ammonia absorbent

Ammonia uptake is a possible alternative to traditional amine-based solutions. During the CO2 absorption
procedure, CO2 is physically absorbed into the liquid phase first before reacting with the ammonia in the
solution. The chemical reactions for the reaction of ammonia with CO2 are shown in Equations (7)–(10)[131].
The CO2-rich solution is heated from 27 to 92 ℃ in a vapour extraction tower, where the ammonium
bicarbonate is broken down to produce CO2[22]. Ammonia solutions have many benefits, such as superior CO2
capture capacity, low thermal and oxidative degradation, negligible corrosiveness, low cost, less regeneration
energy consumption, and the ability to remove a variety of contaminants from flue gas (SO2, NOx, HF, etc.)[61].
퐶푂� + 푁퐻� ↔ 푁퐻� 퐶푂푂푁퐻� (7)

푁퐻� 퐶푂푂푁퐻� + 퐻� 푂 ↔ 푁퐻� 퐻퐶푂� + 푁퐻� (8)

푁퐻� 퐻퐶푂� + 푁퐻� ↔ (푁퐻� )� 퐶푂� (9)

푁퐻� 퐶푂푂푁퐻� + 퐶푂� + 퐻� 푂 ↔ 푁퐻� 퐻퐶푂� (10)

However, the high volatility of ammonia leads to its escape which is a significant obstacle to its broader
application. In the CO2 capture process, ammonia evaporates from the liquid phase into the gas phase, escaping
from the top of the absorption and stripping columns. A conceptual diagram of the ammonia escape during
absorption and desorption processes is shown in Figure 12. The escaped ammonia can react with CO2 in the
gas phase to form ammonium salt solids, which could lead to the blockage of equipment such as pipes and
valves and a reduction in the heat transfer efficiency of the heat exchanger. Additionally, if not appropriately
handled, ammonia can leak into the air, resulting in significant secondary atmosphere contamination. Some
effective methods are developed to contain ammonia leaks or to reduce the chances of ammonia escape.
Generally, ammonia based process needs to be operated at temperatures below 25 ℃ and purging devices are
needed at the CO2 absorber outlet to prevent excessive ammonia evaporation.
For solving the issue of high volatility of ammonia, researchers developed the chilled ammonia process
(CAP) in 2006. In CAP, the ammonia absorption is carried out at 0–10 ℃, limiting the NH3 evaporation to 6%
of the solvent, while traditional aqueous ammonia processes often result in losses of NH3 up to 9%. As for the
regeneration step, the CO2-rich stream is compressed and heated to around 100 ℃ to release CO2, and it has
been stated that the energy consumption of the CAP process is just half of the standard MEA process[207].
Nevertheless, the CAP process requires additional cooling devices and multiple columns, increasing capital
costs. In addition, low-temperature conditions reduce the gas-liquid mass transfer rate and lead to the formation
of solids, which affects the absorption efficiency.

Figure 12. Schematic of ammonia escape in the absorption and desorption process. Reproduced with permission from Wang et
al.[208].
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 28/47

3.2.3. Carbonate absorbent

As early as 1904, German patents explored the absorption of CO2 using carbonates at high
temperatures[209]. Subsequently, Benson et al.[210] created the Benfield technique, which reduces the expense
of the carbon capture process by using potassium carbonate as the CO2 absorbent under high temperatures and
pressure. Following that, the ability to absorb CO2 has often been studied using carbonate solutions such as
potassium carbonate and sodium carbonate[209–212]. The chemical reactions of these process are given below.
In carbonate solutions, CO2 is hydrated to bicarbonate HCO3- as shown in Equation (11). The rate liming step
is shown in Equation (12).
퐶푂� + 퐶푂��� + 퐻� 푂 ↔ 2퐻퐶푂�� (11)
퐶푂� + 푂퐻 � ↔ 퐻퐶푂�� (12)
Chemical absorption using carbonate solutions offers the following benefits: (1) inexpensive raw
materials, (2) low regeneration costs, (3) high absorption capacity, (4) low degradation and corrosion rates,
and (5) low toxicity[213]. However, the main challenge of carbonate solutions is the poor absorption rate. High
pressure (30–60 bar) absorption can be employed to solve this problem[214–216]. It also has been found that
high-temperature absorption is beneficial to increase absorption capacity[217]. High temperature absorption also
provides the benefit of not removing the hydrocarbons from the gas stream prior to absorption, as the
hydrocarbons condense at low temperatures. The high-pressure conditions of the absorption tower allow the
absorption solution to operating at temperatures close to the atmospheric boiling point of the potassium
solution (100–140 ℃) without significant evaporation of the solution. Several activators, such as amines, salts,
and enzymes have also been employed to speed up the absorption rate[131]. Valluri and Kawatra[218] proposed
that stirring usage also could aid the uptake of CO2 in the dilute slurry of sodium carbonate, leading to a
significant increase in capture efficiency.

3.2.4. Dual-alkali absorbents

The dual-alkali process is also called the Solvay process. Ammonia, the first alkali used in the Solvay
process, acts as a catalyst to speed up the reaction between CO2 and sodium chloride (NaCl) to produce sodium
bicarbonate (NaHCO3). Calcination of sodium bicarbonate produces high-purity CO2 for storage and
commercial-grade sodium carbonate (NaCO3). Calcium hydroxide (Ca(OH)2), the secondary alkali, reacts with
ammonium chloride, allowing ammonia to be recovered. The reaction equations for CO2 absorption and
ammonia regeneration are listed below:
퐶푂� + 푁푎퐶푙 + 푁퐻� + 퐻� 푂 ↔ 푁푎퐻퐶푂� ↓ +푁퐻� 퐶푙 (13)
2푁퐻� 퐶푙 + 퐶푎(푂퐻)� ↔ 2푁퐻� + 퐶푎퐶푙� + 2퐻� 푂 (14)
However, the process needs to calcine large quantities of limestone to regenerate the primary alkali, which
consumes a high amount of energy and produces extra CO2. According to Equations (13) and (14), the
calcination of the limestone releases one mole of CO2 for every two moles that are collected.
퐶푎퐶푂� → 퐶푎푂 ↓ +퐶푂� (15)
Overall reaction equation:
2퐶푂� + 2푁푎퐶푙 + 퐶푎푂 + 퐻� 푂 ↔ 2푁푎퐻퐶푂� ↓ +퐶푎퐶푙� (16)
In order to overcome the disadvantages of the Solvay process, a modified method was proposed by Huang
et al.[219]. Methylaminoethanol (MAE) was used as the main base for CO2 absorption instead of ammonia in
their study. The second step of the dual-alkali process is to use the secondary base to regenerate the primary
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 29/47

base. It regenerates ammonia by using activated carbon (AC) instead of limestone. Due to the alkalinity of the
AC, the Hydrochloric acid (HCI) is chemisorbed by the AC. The ammonia is recovered in this reaction.
푁퐻� 퐶푙 + 퐴푐푡푖푣푎푡푒푑 퐶푎푟푏표푛 ↔ 푁퐻� + 퐴푐푡푖푣푎푡푒푑 퐶푎푟푏표푛 ∗ 퐻퐶푙 (17)
퐴푐푡푖푣푎푡푒푑 퐶푎푟푏표푛 ∗ 퐻퐶푙 + 퐻� 푂 ↔ 퐴푐푡푖푣푎푡푒푑 퐶푎푟푏표푛 + 퐻퐶푙 ∗ 퐻� 푂 (18)

Before dual-alkali absorption, the gas stream must be treated in a denitrification/desulphurization step.
Because acidic impurities (SOx and NOx) and ash in the flue gas will interact with the MAE to create thermally
stable salts, which heavily decreased absorption rate[219]. A summary of the advantages and disadvantages of
chemical absorption is concluded in Table 12.

Table 12. The advantages and disadvantages of chemical absorption using different solutions.

Absorbent Advantages Disadvantages

Amine solution 1. Fast absorption rate and high absorption capacity. 1. Solution regeneration consumes a lot of
2. Proven technology with many practical applications. energy.
2. Highly corrosive to equipment.
3. Susceptible to oxidation and degradation.
Ammonia solution 1. High absorption loading. 1. Ammonia gas is highly volatile and easily
2. Not easily corroded and degraded. escapes.
3. Regeneration is relatively easy. 2. Causes pollution and equipment damage.
Carbonate solution 1. Low solvent cost. 1. Slow reaction rate.
2. Low corrosion and degradation rates. 2. Strong corrosive.
3. Low toxicity.
Dual-alkali solution 1. Low corrosion and degradation rates. 1. Gas stream must be treated in a
2. Low toxicity. denitrification/desulphurization step.
2. The calcination of limestone causes high
energy penalty.

3.3. Membrane separation process

Membrane separation is relatively a new method for selectively removing a component from a mixture.
Membranes are semi-permeable barriers that are separated mainly by four mechanisms: Knudsen diffusion,
surface diffusion, molecular sieving, and configurational diffusion[61]. The main mechanism of membrane gas
separation is molecular sieving. The advantages of membrane separation technology include simplicity of
installation, simple operation, low energy consumption, and minimal environmental effect. However, the high
cost of the module, the large footprint, and the relatively weak durability of the membrane material are the
main challenges which limit the wider application of membrane-based separation[118].
Membranes are the critical factor of the separation process, and the membrane materials usually determine
the separation efficiency. Membrane materials are generally classified as inorganic (ceramics, zeolites, metal
oxides), organic (acetate membranes, polysulfone, polyamides), and mixed matrices[61].
As displayed in the right panel of Figure 13, the membrane technology can be separated into two
categories: membranes for gas separation and membranes for gas absorption. Lately, the membrane gas
separation technology has attracted massive attention as it is a simple operation and does not involve
regeneration and chemical reactions[221]. In membrane gas separation process, CO2-containing gas is pumped
into a membrane separator in the membrane system for gas separation at high-pressure conditions[21]. CO2
travels through the membrane preferentially and is collected at reduced pressure on the other side. Permeability
and selectivity of membrane materials are two main characteristics that affect membrane separation
performance. Pressure, temperature, and the concentration of a specific gas are additional factors that influence
the separation performance. The rate at which a specific gas flows across a particular membrane surface area
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 30/47

is known as permeability (transport coefficient). The gas flow may be calculated if the membrane’s
permeability, size, and trans-membrane driving force are known. Typically, the pressure differential between
the feed side and the permeate side acts as the trans-membrane driving force for an ideal gas. Based on this,
most studies use the assumption that the feed gas is compressed to a greater pressure and the permeability is
fixed at atmospheric pressure. Selectivity (separation coefficient) refers to the preference of gas passage
through the membrane, based on the high or low permeability of different gas types. In recent years, more
emphasis has been placed on gas flux rather than permeability, as membranes can increase the gas flux through
the membrane without losing selectivity[222]. Since the permeability of a membrane is inversely proportional
to the separation area required, using a membrane with a high permeability may minimise costs. However,
permeability and selectivity often trade-off, with high permeability membranes typically being less selective
and vice versa. Reaching this limit is a key goal in membrane research in order to attain high permeability and
high selectivity. According to the research of Robeson, this trade-off effect may be represented as the top limit
of membrane performance[35].

Figure 13. Left: transport mechanism of gas separation membrane. Reproduced with permission from Vaezi et al.[220]. Right:
principle of (a) gas separation membrane and (b) gas absorption membrane. Reproduced with permission from Chao et al.[22].

The gas absorption system employs a solid microporous membrane to extract CO2 from a gas stream.
This system achieves a high CO2 removal rate by avoiding issues like flooding, foaming, channelling, and
entrainment. Notably, the required equipment is more compact compared to membrane separator setups[223].
Despite these advantages, the majority of membrane technology applications are still in the developmental
phase. Additionally, effective membrane separation necessitates significantly high flue gas pressures and CO2
concentrations of 20% or higher. This becomes challenging when dealing with the low CO2 partial pressure
commonly found in post-combustion flue gas, where the CO2 content is typically only around 4%. In such
scenarios, the use of multistage membrane systems could present a viable solution[22]. Favre et al.[224]
discovered that in comparing membrane separation with basic amine absorption, it’s evident that the energy
consumption of membrane separation significantly exceeds that of a basic amine system when dealing with
CO2 streams containing CO2 concentrations of 10% or less.

3.4. Adsorption process

Adsorption is an important alternative method to absorption in post-combustion capture due to its
potential to reduce energy penalty for regeneration[225]. The adsorption process also holds the merits of
requiring simple and easy-to-operate equipment, and being more sustainable. However, it too suffers from
poor separation efficiency when dealing with large gas streams[118].
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 31/47

Chemical adsorption generates covalent bonds between the gas molecules and the adsorbent surface,
while physical adsorption depends on weak van der Waals forces[225]. The adsorption process generally consists
of two columns filled with adsorbents; while one is adsorbing, the other is desorbing simultaneously. Flue
gases rich in CO2 are always passed to the already regenerated column for adsorption. For this reason, these
techniques are called swing adsorption[226]. Depending on the desorption method, swing adsorption methods
can be classified as pressure swing adsorption (PSA), vacuum swing adsorption (VSA), temperature swing
adsorption (TSA), electro swing adsorption (ESA) and some composite techniques such as temperature-
vacuum swing adsorption (TVSA), pressure-vacuum swing adsorption (PVSA)[22].
The PSA technique uses high-pressure adsorption and low-pressure desorption (around atmospheric
pressure) while maintaining a constant working temperature. The TSA technology is based on low-temperature
adsorption in the adsorber column and high-temperature desorption in the regenerator, while the pressure is
almost constant for both columns. In addition, composite techniques such as pressure/vacuum swing
adsorption (PVSA) are often studied due to their low energy demands and high regeneration efficiency[22].
CO2 adsorption materials can be categorized based on their chemical composition, encompassing
activated carbons, zeolites, metal organic frameworks (MOFs), amine-functionalized adsorbents, alkali-doped
metal oxides, and other compounds. These materials have demonstrated a notable capacity for CO2 adsorption,
even when subjected to higher CO2 pressures, outperforming the typical applications of VSA or TSA
methods[227]. The effectiveness of the adsorption process in capturing CO2 is significantly influenced by the
characteristics of the adsorbents. Extensive investigations have been conducted to evaluate the potential of
various porous materials for CO2 adsorption[228–230]. Two primary mechanisms are considered: physical
adsorption, which relies on van der Waals forces between CO2 and the adsorbent, and chemical adsorption,
where CO2 forms a chemical bond with the surface of the adsorbent. Specific criteria have been established to
gauge the suitability and efficiency of CO2 adsorbents, encompassing aspects like capacity, selectivity, rates
of adsorption and desorption, required temperature conditions, thermal and mechanical stability, regenerability,
manufacturing and regeneration costs, and the influence of impurities (such as H2O, SO2, and NOx) present in
flue gas[22]. Environmental considerations are also taken into account. In practical applications, it’s vital to
comprehensively assess the pros and cons of an adsorbent material within the context of its real-world
implementation, factoring in cost considerations[231].
Several prerequisites of adsorbents are necessary to achieve effective CO2 adsorption: (i) high tolerance
for common impurities like SOx, which can adhere to the adsorbent surface and resist regeneration; (ii) a
significant total exposed surface area providing numerous adsorption sites; (iii) rapid rates of adsorption and
desorption to minimize the time the gas spends in the column; (iv) an optimal distribution of pore sizes enabling
efficient gas diffusion within particles; (v) strong selectivity for CO2 and weak selectivity for other impurities
in flue gas; and (vi) the application of gentle desorption conditions, such as maintaining a minimal temperature
difference between adsorption and desorption.
Therefore, the performance of adsorption is based on (i) the difference in size and shape of the component
molecules in the gas stream, (ii) the influence of thermodynamic equilibrium effects, and (iii) the different
diffusion rates of the gas stream components[225].

3.5. Comparison of various post-combustion techniques

Table 13 summarises the benefits and drawbacks of the different post-combustion CO2 capture systems.
Although the fact that each technique has its advantages, none of them is sufficient to economically manage
the significant quantities of post-combustion flue gas from power plants or other industrial sectors. The
following factors usually constrain these technologies:
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 32/47

1) CO2 partial pressure/concentration: Technologies such as physical absorption, adsorption, membrane, and
cryogenic, usually need high CO2 partial pressure/concentration in the flue gas since all of them work by
physical mechanism. Especially a CO2 concentration over 20% is required for membrane separation
technology[221].
2) Impurities in flue gas: The separation performance of adsorption and membrane can be influenced by the
water and other gas (SOx and NOx) impurities. These impurities will reduce the selectivity and permeation
of the adsorbents and membranes; it will cause dangerous operational problems such as clogging of piping
heat exchangers and other equipment.
3) Processing capacity: The adsorption technique has poor separation performance when handling huge
emission quantities.
4) Energy consumption: In the chemical absorption process, high energy is consumed to heat the CO2-riched
absorbents for regeneration.
5) Separation efficiency: The bulk removal of CO2 from flue gas mainly involves physical absorption and
membranes. Multiple stages of recycling are needed for the membrane technology to achieve high degrees
of separation.

Table 13. The advantages and disadvantages of different post-combustion CO2 capture technologies.
Capture technologies Benefits Drawbacks
Absorption 1. High absorption rate and efficiency (>90%) 1. Considerable energy consumption for
2. Could be used at low partial pressures of CO2. solvent regeneration.
3. The most widely used technology in practice. 2. Environmental impact caused by absorbent
degradation or evaporation.
3. Equipment corrosion.
Adsorption 1. The adsorbent has little environmental pollution and 1. The cool-down and dehydration treatment
can be recycled. required for the flue gas prior to adsorption.
2. The adsorption efficiency is relatively high (>85%). 2. Impurity gases can have an irreversible
effect on the adsorbent.
Membrane 1. Low environmental pollution. 1. Gas needs to be compressed prior to
2. Direct separation of CO2 without energy penalty. separation.
3. Simple and modular designs. 2. Gas impurities can have an irreversible
effect on the membrane.
3. Limited separation purity.
4. Large footprint required.

Among all available options discussed above, amine-based chemical absorption is one of the most
promising separation methods. The amine absorption process has higher capture efficiency (>90%) and larger
processing capacity; Furthermore, it exhibits efficacy at low CO2 partial pressures and demonstrates the
capability to capture multiple acid gases (including CO2, NOx, and SOx) from flue gases while generating
valuable by-products[232]. The key drawbacks are high energy consumption for regenerating the absorbents and
potential environmental impacts related to absorbent degradation. However, advanced absorbents have been
developed to overcome these problems by lowering the regeneration temperature and energy consumption. In
the next section, we shall summarize the advancements in solvent formulations made in the recent past to
overcome the issue of high thermal penalty and solvent degradation.
It should be noticed that both of physical absorption and adsorption relies on physical driving force to
capture the CO2, but there are significant differences between these two techniques. For physical absorption,
the CO2 is dissolved in the liquid phase without changing its chemical structure, and for CO2 absorption, which
generally occurs between the gas phase and the liquid phase[233]. In physical absorption, the solvent capacity
increases nearly linearly with pressure following Henry’s law, and the solvent is regenerated by reducing the
pressure (flash). As for adsorption, CO2 molecules are adhered to the surface of a solid material. This involves
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 33/47

weak van der Waals forces, electrostatic interactions, or other surface interactions[234], these forces are
relatively weaker compared to chemical bonds, resulting in adsorption that is generally more reversible than
absorption. The adsorption is always occurred between gas phase and porous solid. Due to the adsorption is
typically more reversible than physical absorption, CO2 molecules can be released easily from the surface by
altering conditions like temperature, pressure, or gas composition[235–236]. However, for enhancing the CO2
capture performance in adsorption, the modification strategy is always taken such as amine-impregnated[237].
In this composite material, van der Waals forces and chemical absorption coexist. In summary, CO2 capture
by physical absorption involves the incorporation of CO2 into a liquid with solubility, while CO2 capture by
adsorption involves attaching CO2 to the surface of a solid material with weaker van der Waals forces.

4. CO2 utilisation options

In addition to storage, carbon capture and utilisation (CCU) investigates various uses for CO2. The
procedure must be economically feasible, safe, and environmentally benign[17]. In recent research, major areas
of study for CO2 utilisation including (i) chemicals and fuels conversion by using CO2 as feedstock, (ii) CO2
mineralization to solid carbonates, (iii) desalination by CO2 for water production, and (iv) enhanced oil/gas
recovery. There are still numerous basic and technical problems to be resolved in the development of these
technologies to assure net CO2 emissions. For instance, creating efficient thermal and (photo)electrochemical
catalytic reaction pathways, comprehending the processes that lead to the creation of inorganic carbonate in
minerals and industrial waste systems, or speeding up biological CO2 conversion pathways, among other
things[8].

Figure 14. Various carbon-utilization pathways. Reproduced with permission from Al-Mamoori et al.[8].

4.1. Enhanced oil/gas recovery

EOR/EGR is a kind of technique that involves injecting a chemical into the storage reservoir in order to
repressurize a rock and extract any entrapped oil/gas[238].
During CO2-EOR, the injected CO2 interacts with the oil, releasing it from its often difficult-to-recover
rock structure. This stream is then driven to the surface, where CO2 is extracted from the oil and injected into
the cycle to continue the cycle. Typically, this technology yields more barrels per reservoir than conventional
oil recovery techniques. CO2 flooding is one of the most common and successful EOR procedures because, by
inflating the oil, it makes it lighter and easier to extract[239]. Recent research has focused on extracting CO2
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 34/47

from potentially hazardous gas streams, such as flue gas and other industrial gas effluents, as opposed to using
naturally occurring CO2. Since 1972, when CO2-EOR operations began in the world’s most desirable CO2-
EOR location, the Permian Basin in Texas, CO2-EOR has been a financially successful endeavour in the United
States. It has generated over 30 billion barrels of oil, of which 1.3 billion barrels were produced using CO2 as
the recovered medium.
EOR technologies are challenged by a number of difficulties. Fluid properties and capillary pressure
reduce the efficacy of CO2 flooding as a consequence of the varying geological formations across wells. In
addition, a multitude of parameters, such as fluid production rates, the corrected neutron log (CNL), and the
production log, are required for efficient execution[240]. In spite of these difficulties, CO2 EOR/EGR has gained
a considerable lot of interest and is anticipated to increase rapidly in the near future despite these challenges.
Overall, CO2 EOR/EGR is a promising approach applicable to the great majority of reservoir types for
enhanced oil/gas recovery. Despite this, EOR provides just 3% of CO2 usage as now. Although the price of
CO2 has slowed progress in this sector, its usage is continuously increasing and various facilities have adopted
this technique in their reservoirs[239–242].

4.2. Chemicals and fuels conversion by using CO2 as feedstock

Conversion CO2 to valuable chemicals or fuels is considered as the most potential method in CO2
utilization. Furthermore, it validates CO2 extraction and may partly replace fossil fuels as the primary energy
source. It may provide novel methods for creating environmentally friendly technology to augment traditional
fossil fuels[17].

4.2.1. Chemical production

CO2 is a useful feedstock for the production of several high-quality compounds. Urea (160 Mt/year),
inorganic carbonates (60 Mt/year), polyurethane (18 Mt/year), acrylic acid (10 Mt/year), polycarbonates (4
Mt/year), and some alkylene carbonates (Kt/year) are the most major usage[9]. The greatest market for CO2
usage is in producing urea, a significant fertiliser. It is also a key ingredient to produce fine chemicals and urea
resins, as well as an initial feedstock for synthesising of polymers and pharmaceuticals[13].
Given the demanding conditions of high temperature and pressure involved in the process, the use of
heterogeneous catalysts with excellent performance and numerous active sites becomes essential. Achieving
high-performance catalysts is imperative for the electrochemical reduction of CO2 under mild conditions. In
Aresta et al. study, various catalyst electrodes (Sn/Cu, BiSn/Cu, Bi2Sn/Cu, Bi3Sn/Cu, Bi4Sn/Cu, and Bi/Cu)
were fabricated through electrodeposition, and their effectiveness, stability, and selectivity in the reduction of
CO2 to formic acid were systematically assessed[243].

4.2.2. Fuels production

The fuels that converted by CO2 including methane, methanol, syngas, and alkanes. CO2 is a
thermodynamically stable molecule, therefore using it takes huge amonut energy and catalyst to produce these
chemical[14]. The two most major processes for creating fuels from collected CO2 are hydrogenation and dry
reformation of methane (DRM). CO2 hydrogenation has the ability to recycle CO2, store H2, create fuel, and
solve the issue of electric energy storage, making it a very appealing strategy for CO2 usage. The Fischer–
Tropsch (FT) process uses the DRM as a significant route for the synthesis of methanol and a range of other
liquid fuels[244].
Many scientists are now investigating DRM as a means of producing syngas from CO2, when compared
to partial oxidation and steam reforming, the syngas produced by DRM is purer[245]. Additionally, DRM may
be used at distant natural gas sources to produce liquid fuels, which are more convenient to transport than
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 35/47

gaseous fuels, since the quantity of unreacted methane is just 2%, which is less than that in steam reforming.
The DRM reaction has been widely tested using Ni, Ni-Co, Ru, and Rh supported on silica, alumina, and
lanthanum oxide[5,11]. High-activity, very stable catalysts for DRM have been developed, but finding a catalyst
that can withstand the high temperatures required for this reaction is still difficult; High temperatures cause
most catalysts to deactivate.

4.3. CO2 mineralization

The process known as carbon mineralization involves the creation of solid carbonate minerals, including
calcite, magnesite, dolomite, and various hydrated magnesium carbonate minerals like nesquehonite. This is
achieved by the interaction of carbon dioxide (in its gas, liquid, dissolved in water, or supercritical form) with
rocks rich in calcium or magnesium. The sources of magnesium and calcium are primarily mafic and ultramafic
rocks (such as mantle peridotite, basaltic lava, and ultramafic plutons), mining tailings from these rock types,
and industrial by-products like cement kiln dust, steel slag, and fly ash)[8].
The mineralization process is energy intensive with high pressure (10–15 MPa) and temperature (150–
600 ℃)[246]. In addition, the carbonation reaction period is lengthy (6–24 h), and minerals must be extracted
(37 m). Moreover, the exothermic character of the mineralization process and the geothermal gradient (up to
20 ℃ per kilometre) contribute to a decrease in energy usage[247]. Furthermore, CO2 purity is not necessary,
and flue gas may be used without the removal of pollutants including SOx and NOx.

4.4. CO2 desalination

The collected CO2 might be employed to eliminate total dissolved solids (TDS) then convert brine to
water[8,13,248]. In CO2 desalination process, firstly, the sea water is mixed with ammonia, when exposed to CO2,
weak bonds begin to form, resulting in the removal of ions from the water phase. The later NH4Cl may be
recycled by thermal processes using calcium oxide or employed as a raw material for the production of
ammonia and chlorine[248]. The cost of CO2 desalination has been researched by 2013 DOE (US deparment of
energy) report, which is estimated around $0.83 per litre. Currently, whereas CO2 remains an appealing
desalination option, but this technique is unlikely marketable due to cost[8].

5. Conclusion and outlook

This article discusses and summarises the recent developments in carbon capture process. In recent years,
significant advancements have been made in the design and development of various CCU systems, with a few
instances being implemented on a commercial scale. However, the majority of the available technologies are
so far limited to lab scale.
Within the various carbon capture methods, the post-combustion process is the most promising in short
term, as it can be easily installed into existing power plants. Amine absorption method is currently the most
mature technology. Typically, a 30 wt% aqueous MEA solution is considered the benchmark for CO2 capture
solvent. However, the major problems it faces are the high energy consumption for regeneration, oxidative and
thermal degradation of amines, and corrosion of equipment. Thus, developing advanced absorbents that can
reduce energy penalty and maximize the CO2 capture capacity are the primary research goals. Recently, a
series of novel amine absorbents have been proposed and investigated that include blended amine absorbents,
phase change absorbents and non-aqueous absorbents. Among them, blended amine absorbents combine the
advantages of different amines to compensate for their disadvantages, phase change absorbents significantly
reduce the volume of solution to be regenerated, and non-aqueous amine absorbents use organic solvents with
low specific heat capacity and heat of vaporisation instead of water as a solvent to significantly reduce the
energy requirement to regenerate the solution. However, the regeneration energy is still high as the blended
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 36/47

amine solution still uses an amine that produces a stable carbamate to enhance absorption rate. The CO2-
enriched phase of the phase change absorbent has a high viscosity which affects desorption efficiency and
increases the capital and operating costs. Non-aqueous absorbents can directly replace conventional aqueous
solutions for CO2 capture without extra cost, but different non-aqueous solvents have their own drawbacks.
For example, alcohols, such as methanol and ethanol, can lead to large amounts of solvent volatilisation,
resulting in solvent loss and contamination; glycols and other polyhydroxy alcohols show non-linear increase
in viscosities after absorption; ionic liquids have a complex and expensive synthesis process. These factors
have been obstacles to further application and development of non-aqueous amine absorbents for CO2 capture.
An ideal absorbent should have low volatility, maintain a low viscosity, and energy-efficient regeneration. At
the same time, it should also have a relatively good absorption performance, and cycling capacity.
Future research should focus on hybrid processes that integrate CO2-capture and utilisation systems, since
thermodynamic assessments have shown the energy and cost effectiveness of such systems (by decreasing
both capital and operating expenses). To better assess the materials development, process operating needs, and
process scalability, more research on hybrid process is required.

Acknowledgments
We thank the Wiley Online library, Elsevier and the owners of Figures 3, 6–13 for their permissions to
use the diagrams. Authors gratefully acknowledge the Engineering and Physical Sciences Research Council
(EPSRC) of the UK [grant number EP/V041665/1].

Conflict of interest
The authors declare no conflict of interest.

Abbreviations
[bmim][AC] 1-butyl-3-methylimidazolium acetate
[bmim][BF4] 1-butyl-3-methyl-imidazolium-tetrafluoroborate
[bmim][DCA] 1-n-butyl-3-methylimidazolium dicyanide
[bmim][OTf] 1-butyl-3-methylimidazolium trifluoromethanesulfonate
[C2OHmim][DCA] 1-(2-hydroxyethyl)-3-methylimidazolium dicyanamide
0EG Ethylene glycol
2-EE 2-ethoxyethanol
2-ME 2-Methoxyethanol
2-PE 2-piperidineethanol
AEEA Aminoethylethanolamine
AMP 2-amino-2-methyl-1-propanol
BECCS Bioenergy with carbon capture and storage
CAP Chilled ammonia process
CES Clean energy system
CLC Chemical looping combustion
DAC Direct air capture
DEA Diethanolamine
DEA Diethanolamine
DEEA Diethylethanolamine
DEG Diethylene glycol
DEGMEE Diethylene glycol monoethyl ether
DEPG Dimethyl ether of polyethylene glycol
DETA Diethylenetriamine
DGA Diglycolamine
DMEA Dimethylethanolamine
DMF Dimethylformamide
DMSO Dimethyl sulfoxide
EG Ethylene glycol
EMEA EthylMonoethanolamine
IGCC Integrated gasification combined cycle
Clean Energy Science and Technology Volume 1 Issue 1 (2023) 37/47

MAE Methylaminoethanol
MDEA Methyldiethanolamine
MOF Metal organic framework
MWCNT Multi-walled carbon nanotubes
NGCC Natural gas combined cycle
NMF N-methylformamide
NMP Normal methyl pyrrolidone
nMWCNT Multi-walled carbon nanotubes
PCC Post combustion capture
PMDETA Pentamethyldiethylenetriamine
PrOH 1-propanol
PZ Piperazine
TEA Triethylamine
TEA Triethylamine
TETA Triethylenetetramine

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