A Review on the State-of-the-Art and Commercial Status of Carbon Capture Technologies

Abstract

Carbon capture technologies are largely considered to play a crucial role in meeting the climate change and global warming target set by Net Zero Emission (NZE) 2050. These technologies can contribute to clean energy transitions and emissions reduction by decarbonizing the power sector and other CO₂ intensive industries such as iron and steel production, natural gas processing oil refining and cement production where there is no obvious alternative to carbon capture technologies. While the progress of carbon capture technologies has fallen behind expectations in the past, in recent years there has been substantial growth in this area, with over 700 projects at various stages of development. Moreover, there are around 45 commercial carbon capture facilities already in operation around the world in different industrial processes, fuel transformation and power generation. Carbon capture technologies including pre/post-combustion, oxyfuel and chemical looping combustion have been widely exploited in the recent years at different Technology Readiness level (TRL). Although, a large number of review studies are available addressing different carbon capture strategies, however, studies related to the commercial status of the carbon capture technologies are yet to be conducted. In this review article, we summarize the state-of-the-art of different carbon capture technologies applied to different emission sources, focusing on emission reduction, net-zero emission, and negative emission. We also highlight the commercial status of the different carbon capture technologies including economics, opportunities, and challenges.

1. Introduction

The 2015 Paris Agreement sets the goal to keep the global temperature rise to well below 2 °C, with a preferential target of 1.5 °C, compared to pre-industrial levels. Reduction of global CO₂ emission to net zero by 2050, a target that an increasing number of countries are putting into legislation, will be a key enabler of the efforts to limit the global temperature rise. The energy sector is the largest greenhouse gas emitter today, and thus, a main contributor to exacerbating climate change impacts [1,2]. Coal- and gas-fired power plants continue to dominate the global electricity sector, accounting for nearly two-thirds of total power generation—a share that has remained steady since 2000, despite the rise of low-cost renewable energy. Since then, fossil fuel-based electricity generation has grown by 70%, reflecting the relentless increase in global power demand. The electricity sector is also the largest contributor to energy-related greenhouse gas emissions, responsible for nearly 40% of the global total (Figure 1). Despite the pressing need for mitigating emissions across the economy, 2018 recorded the highest amount of CO₂ emissions from the power sector at around 13.6 Gton [3].

In addition to the rapid expansion of renewable energy generation, in order to achieve Net Zero Emissions (NZE) by 2050 and keep the temperature rise within 1.5 °C, there is an urgent need to tackle and dramatically reduce large-scale power sector emissions. Notably, two flagship reports [1,5] published by International Energy Agency (IEA) state that it would be virtually impossible to meet NZE by 2050 without implementation of carbon capture technologies, the focus of this review. Carbon capture technologies can contribute to clean energy transitions and emissions reduction in several ways:

(i)

Carbon capture technologies can be integrated into existing power and industrial facilities to prevent the release of up to 600 billion tonnes of CO₂ over the next 50 years.

(ii)

Carbon capture technologies can provide a solution for some of the most challenging emissions such as those from heavy industries that account for almost 20% of global CO₂ emission. For example, carbon capture technologies are virtually the only technological solution to reduce emission from the cement production, and a cost-effective approach to curb emissions also from iron, steel, chemical manufacturing.

(iii)

Carbon capture technologies play a crucial role in enabling cost-effective, low-carbon hydrogen production and can accelerate the scale-up needed to meet growing demand for zero-emission solutions in transport, industry, and buildings.

(iv)

Carbon capture technologies can also remove CO₂ directly from the atmosphere in the case of emissions that cannot be avoided and thus play a critical role in removing carbon from atmosphere to provide net-zero emission system [1,3,5].

In this review paper, we present the state-of-the-art of different carbon capture technologies applied to different emission sources, focusing on emission reduction, net-zero emission, and negative emission. We also highlight the commercial status of the different carbon capture technologies including economics, opportunities, and challenges.

2. Technology Readiness Level (TRL) of Carbon Capture Technologies

Today, carbon capture technologies are at different levels of maturity. Some carbon capture technologies are already deployed at large scale, while others holding promise for improved performance need further development. One way to evaluate where a technology lies in its journey to commercialization is through a TRL scale. TRL scales offer a common framework that can be applied to any technology to measure and evaluate the maturity of a specific innovation throughout its research, development and deployment phase progression. TRLs were originally developed by National Aeronautics and Space Administration (NASA) in the 1970s [5]. The different TRL categories and scales are presented in Figure 2. Several carbon capture technologies widely deployed today include chemical absorption of CO₂ from natural gas processing and ammonia production. Several carbon capture technologies have been successfully demonstrated at scale over the past decades, yet they remain in the early stages of adoption. These are chemical absorption of CO₂ from coal-fired power plants (IGCC), hydrogen production from natural gas, and direct air capture (DAC). Several other applications such as CO₂ capture from cement, iron, and steel production are still at the demonstration or prototype stage. Each of these emerging applications requires CO₂ capture technologies to be carefully adapted to the specific conditions of the respective industrial processes [5].

Among all the carbon capture technologies, chemical absorption using amine-based solvent is the most advanced CO₂ capture technique achieving TRL 9–11. This method has been in use for decades and is currently deployed in various small- and large-scale projects worldwide, including in power generation, gas processing, steel manufacturing, and fertilizer production. A number of large-scale carbon capture projects employing novel chemical absorption techniques for CO₂ capture are also in the planning phase [6].

Physical CO₂ separation methods include adsorption, absorption, cryogenic separation, membrane separation, dehydration, and compression. Currently, high TRL (9–11) physical separation methods are in use in several natural gas processing, ethanol, methanol, and hydrogen production facilities. Oxyfuel technology, which uses pure O₂ in the combustion step, is at the large prototype or pre-demonstration stage (TRL 5 to 7). A number of projects employing this technology have been demonstrated in coal-based power generation and in cement production plants. The maturity of membrane-based CO₂ separation technologies vary depending on the fuel type and application. In natural gas processing, this technology is currently at the demonstration stage (TRL 6–7). Petrobras in Brazil operates the world’s only large-scale CO₂ capture facility that utilizes membrane separation technology. Currently, Calcium looping technology is at the large prototype stage (TRL 5–6). Several pilot plants have been tested for applications such as coal-fired fluidized bed combustors and cement production. Two European projects are currently advancing calcium looping technology for steel and cement production at the pilot and pre-commercial stages (Technology Readiness Levels 6–7). Meanwhile, chemical looping technologies—developed by academic institutions, research organizations, and companies in the power sector—are being tested in approximately 35 pilot projects worldwide, with TRLs ranging from 4 to 6 [5].

3. CO₂ Capture Pathways

Carbon Capture, Utilization and Storage (CCUS) technology aims at capturing CO₂ from either point sources such as industrial processes or fossil fuel-based power plants, or directly from the atmosphere, with a view to either storing permanently underground, or utilizing through new chemistries [7,8]. The main industrial sources of CO₂ are power plants, oil refineries, biogas sweetening, ammonia production, and the cement, iron, and steel industries. Importantly, due to the distinct effluent gas mix and CO₂ concentration of different emission sources, a one-size-fit-all approach to CCUS technology is not viable [7].

Notwithstanding the significant efforts pursued to date to reduce CO₂ emissions, billions of tons of CO₂ are still being discharged into the atmosphere every year. In this scenario, the UN IPCC has also indicated CO₂ capture as a necessary component of the portfolio of technologies required for abate CO₂ concentration in the atmosphere [9]. CO₂ is mostly produced during combustion processes, where the type of combustion process directly influences the possible CO₂ capture pathway. Technically, three main pathways are available for CO₂ capture from point sources. These pathways comprise pre-combustion, post-combustion, and oxyfuel combustion [10]. For instance, post-combustion technology is only applicable when CO₂ concentrations in exhaust gases range between 4–14% by volume, which restricts its use. However, these methods offer the advantage of capturing highly pure CO₂, which can be utilized in specialized applications such as enhanced oil recovery, urea production, and the food and beverage industry. The possible CO₂ capture pathways are illustrated in Figure 3. In the following section, each of these pathways is discussed.

3.1. Post-Combustion CO₂ Capture

Technologies to separate pure CO₂ from emission sources have been in place for many years. In this process, CO₂ is extracted from the flue gas after combustion has occurred. Post combustion capture is the preferred technology for retrofitting existing power plants, or other combustion-based CO₂ emission sources [7,11]. As shown in Figure 3, post-combustion capture methods include absorption by solvents, adsorption by solid sorbent, membrane separation, cryogenic separation, pressure swing and vacuum swing adsorption. These approaches are used in a range of industrial processes such as power plants, cement industries, production of ethylene oxide, iron, and steel industries. A major challenge of post-combustion CO₂ capture systems are the high capital costs and the large energy demand for the regeneration of absorbent and/or adsorbent. According to the U.S. National Energy Technology Laboratory, implementing post-combustion CO₂ capture could raise electricity production costs by approximately 70% [12].

A schematic diagram of a coal-fired power plant with CO₂ capture facility is presented in Figure 4. In this process, coal is combusted with air in a boiler to generate steam, which then drives a steam turbine to produce electricity. The exhaust gas from the boiler mainly consists of N₂, CO₂, O₂, moisture and impurities. Due to the low concentration of CO₂ (13–15% in coal-fired power plants) and low pressure (15–25 psia), it is challenging to implement an effective and efficient CO₂ capture process. Further, the impurities degrade the sorbent, which reduces the effectiveness of the CO₂ capture process. Additionally, compressing the captured CO₂ from atmospheric pressure to pipeline pressure (around 2000 psia) requires significant energy, substantially reducing overall plant efficiency. Despite these difficulties, post-combustion CO₂ capture remains the preferred CO₂ emission reduction technology in power plants due to its modularity and relative ease of retrofit on existing plants. Of the post-combustion technologies presented in Figure 3, chemical absorption and adsorption are state-of-the-art systems already in commercial use. In addition, pressure swing adsorption, vacuum swing adsorption, and membrane separation are also in use in a few currently operating plants (see Section 4.2).

3.2. Pre-Combustion CO₂ Capture (Decarbonization of Combustion Gas)

Decarbonizing combustion gases involves converting fuel into a hydrogen-rich synthesis gas and capturing the resulting CO₂ from the fuel stream. The resulting low-carbon fuel gas is then used in a combined gas and steam turbine cycle to generate electricity. This mainly includes coal gasification processes that are used in power plants and ammonia production facilities, where coal is converted into hydrogen-rich synthesis gas (CO + H₂) followed by a water-gas shift reaction from which the resulting CO₂ is captured. The decarbonized fuel gas, primarily composed of hydrogen, is then routed to an Integrated Gasification Combined Cycle (IGCC) system for electricity generation. The main changes in an IGCC power plant with carbon capture compared to the plant without carbon capture is the introduction of the CO shift reactor after dedusting and H₂S removal. The process is also used in the Natural Gas Combined Cycles (NGCC) power plants [11]. CO₂ capture occurs after the gasification of coal as shown in Figure 5. Since after the water-gas shift reaction, the fuel gas is at high pressure and H₂-rich, it is preferable to use physical absorbents (See Section 4.2.3) for capturing CO₂ [8,13]. Before the gasification process, an air separation unit (ASU) is placed which separates the nitrogen from the feed air to the gasifier. This technique increases the yield in the gasification processes by removing nitrogen from the syngas reaction, which is thus sustained by an O₂-rich air feed.

However, IGCC with carbon capture is not yet a fully mature technology, and such plants suffer from several disadvantages over IGCCs without carbon capture, which limits wider uptake and application of this technology. They are costlier than a conventional plant and challenging to operate due to the addition of two additional units such as the ASU and the water-gas shift reactor. However, IGCC with carbon capture has the potential for wider uptake and use at scale if government incentives are offered to offset the additional costs [11,14].

3.3. Oxyfuel Combustion

Oxyfuel combustion process is one of the three main routes for technically feasible carbon capture. In oxyfuel combustion, the carbon-containing fuel is combusted with pure oxygen [11]. Oxy-fuel combustion is not a carbon capture technology per se, but rather a process where combustion takes place using pure oxygen instead of air. Therefore, after combustion the flue gas mainly contains CO₂ and steam, where steam is easily separated to obtain pure CO₂ for sequestration [11]. Unlike conventional power plants where the CO₂ concentration in the flue gas ranges from 12–15%, the CO₂ concentration in oxyfuel combustion plants lies at around 89% [8]. The most common oxyfuel combustion process involves the combustion of pulverized coal in nearly pure oxygen (95–99%), which is mixed with recycled flue gas. A schematic diagram of the common oxyfuel combustion of pulverized coal in pure oxygen is presented in Figure 6. The pure oxygen is produced in the ASU through cryogenic method where air is condensed at low temperature (<−182 °C) [8]. Coal combustion in pure oxygen results in very high temperatures, which currently available construction materials cannot withstand, and thus require mixing the pure oxygen feed with the recycled gas stream. Approximately 2/3 of the flue gas flow is recycled back into the boiler so as to replicate combustion conditions similar to those of an air-fired configuration. This mixing provides an oxygen level of around 30–35% in the inlet gas to the boiler [11]. Advanced oxy-fuel combustion systems can be engineered for both low- and high-temperature boiler configurations. In low-temperature designs, flame temperatures are maintained near those of conventional air-fired systems (~1650 °C), while high-temperature configurations can achieve flame temperatures exceeding 2500 °C, enhancing thermal efficiency and reaction kinetics [15].

Oxyfuel combustion technology can be used to produce near-zero emissions electricity from fossil fuel-based power plants. This process offers a number of benefits over the other carbon capture pathways:

-

The boiler and the flue gas cleaning equipment utilize conventional designs, materials, and configurations.

-

The process can be used in any rank of coal.

-

This process can be retrofitted to existing coal-fired power plants with relatively low capital investment compared to post-combustion CO₂ capture systems, offering a more cost-effective pathway for emissions reduction.

The cryogenic separation of oxygen from air constitutes the largest energy penalty in oxyfuel combustion processes. However, ion transport membrane (ITM) is being investigated as a prospective alternative technology for producing large amounts of oxygen economically [16]. Currently the GreenGen project in Tianjin, China is the largest oxyfuel combustion IGCC power plant, with 250 MW power generation capacity. The second largest is the 150 MW Kimberlina power station which is in operation since 2013 In some instances, oxyfuel combustion technology is combined into supercritical CO₂ power cycle for producing electricity. Currently, two oxy-fuel combustion systems integrated with supercritical CO₂ power cycles are operational: NET Power’s Allam cycle and the Trigen Clean Energy Systems (CES) cycle. NET Power commissioned a 50 MW demonstration facility in Texas, which began operation in 2018, while a 300 MW commercial-scale plant is presently under design.

Oxyfuel combustion technology has seen its application also beyond power generation. The four European cement manufacturers—Buzzi Unicem—Dyckerhoff, HeidelbergCement AG, SCHWENK Zement KG, and Vicat—have established a joint research corporation called CI4C (Cement Innovation for Climate) to explore the application of oxy-fuel combustion technology in cement production. In the oxyfuel based cement production process, clinker burning occurs in pure oxygen in the kiln instead of air. As part of the Catch4Climate project, the four partner companies of the CI4C research corporation has constructed a semi-industrial scale oxy-fuel test facility at the cement plant in Mergelstetten, Southern Germany. This facility serves as a central component of their efforts to advance carbon capture technologies in the cement industry. Moreover, several other commercial plants are in design and construction phase worldwide summarized in

Table 1. Summary of the oxyfuel combustion plants [17].

Operation Year	Location	Project	Process	Capacity
In operation
2018	La Porte, TX, United States	NET Power Allam Cycle Demonstration Project	Thermal energy	50 MW
2014	Tianjin, China	GreenGen	IGCC power plant	250 MW
2013	Rancho Cordova, CA, United States	Trigen Clean Energy Systems Kimberlina power station	Electricity generation	150 MW
2025	Mergelstetten, Germany	Catch4climate	Cement production	-
Under design and construction
2027	Cameron Parish, LA, United States	G2 Net-Zero LNG based on Allam Cycle	Natural gas processing	Multiple 300 MW Allam-cycle trains
2025	Alberta, Canada	Frog Lake’s NET Power plant based on Allam Cycle	Electricity generation	300 MW
2026	La Porte, TX, United States	NET Power Allam Cycle commercial plant	Electricity generation	300 MW

.

4. Carbon Capture from Emission Source

Power plants, industrial manufacturing plants and transportation are considered to be the major anthropogenic stationary sources of CO₂ emissions. Industrial manufacturing encompasses a wide range of processes, including oil refining, gas processing, and the production of ammonia, cement, iron, steel, hydrogen, ethylene, and ethylene oxide (Figure 1). In this section, different capture technologies from different emission sources are discussed.

4.1. Chemical Separation

CO₂ capture through chemical separation is employed both in pre- and post-combustion processes. Chemical separation involves (a) solvent-based absorption, (b) chemical looping and (c) calcium looping [5]. In the following section we will discuss both pre- and post-combustion chemical separation of CO₂.

4.1.1. Chemical Absorption

Chemical solvents that are used as absorbents for CO₂ capture are mainly amine-based solvents, alkaline solvents, and ionic liquids. Once the solvent is saturated with CO₂, a weak physical absorption is also observed. Solvent regeneration is achieved via low-pressure thermal input supplied through the reboiler at the base of the stripper column. Because of the high affinity of chemical solvents towards CO₂, this method is mainly used when the effluent gas stream has low partial pressure, namely in coal and gas fired power plants. However, the energy penalty for regeneration is relatively high [18]. Below, different types of chemical absorption methods are discussed.

Amine Based Solvent

The most commonly used solvent for CO₂ capture is monoethanolamine (MEA), an amine-based compound. Amines are organic molecules that contain a nitrogen atom with a functional group. Structurally similar to ammonia, they differ in that one or more hydrogen atoms are replaced by organic groups such as alkyl or aryl chains. Amine-based solvents suitable for CO₂ capture comprise simple amines, e.g., primary (monoethanolamine-(C₂H₅OH)NH₂), secondary (diethanolamine -(C₂H₅OH)₂NH) and tertiary ( methyldiethanolamine, MDEA) ethanolamines, hindered amines, mildly hindered primary -alamine (ALA), moderately hindered—amionomethylpropanol (AMP) and cyclic diamines (piperazine) [11,19].

Amine-based CO₂ capture is based on the reaction between the weak alkanolamine base and the weak acid CO₂ molecule. Amines react with CO₂ to form carbamate and bicarbonate species, as represented by reactions (1) and (2), respectively.

$$2\mathrm{R}\mathrm{N}{\mathrm{H}}_2+\mathrm{C}{\mathrm{O}}_2\leftrightarrow \mathrm{R}\mathrm{N}{\mathrm{H}}_3^{+}+\mathrm{R}\mathrm{N}\mathrm{H}\mathrm{C}\mathrm{O}{\mathrm{O}}^{-}$$

(1)

$$\mathrm{R}\mathrm{N}{\mathrm{H}}_2+{\mathrm{H}}_2\mathrm{O}+\mathrm{C}{\mathrm{O}}_2\leftrightarrow \mathrm{R}\mathrm{N}{\mathrm{H}}_3^{+}+\mathrm{H}\mathrm{C}{\mathrm{O}}_3^{-}$$

(2)

In general, amine-based CO₂ capture is not universally applicable across industrial processes due to the substantial energy demand associated with solvent regeneration. For example, CO₂ capture by MEA is less favorable in cement production plants than it is in combined heat and power (CHP) or IGCC plants, in that the recoverable waste heat from the CHP or IGCC (absent in a cement production plant) can be used for solvent regeneration. MDEA, as previously mentioned, is also applicable for H₂/CO₂ separation. However, as a tertiary amine, MDEA displays slow reaction kinetics with CO₂. Therefore, a higher circulation rate of the liquid is necessary to separate CO₂ from H₂. One major benefit of using MDEA is the lower heat requirement for regeneration. This feature has made MDEA attractive for use in pre-combustion CO₂ capture processes [18]. A process flow diagram of amine-based CO₂ capture is presented in Figure 7. These processes typically comprise the operation of two distinct units—an absorber and a regenerator. In this configuration, the raw syngas coming from the gasifier is contacted with the solvent in a wash column where the lean solvent is introduced from the top of the absorption column. A lean solvent is defined as a solvent phase containing negligible or no concentrations of the target components intended for absorption. In the absorption column, the lean solvent flows downward over the structured or random packing material, facilitating mass transfer as it absorbs CO₂ from the counter-current gas stream introduced at the base of the column. The solvent stream reaching the bottom is called ‘rich stream’ as it is rich in CO₂ absorbed from the flue gas. The rich stream is then directed towards the regeneration process which consists of another gas-liquid contacting column. The regeneration column is equipped with a reboiler at its base and a condenser at the top. The reboiler supplies the thermal energy required to elevate the temperature of the incoming rich solvent, thereby facilitating the dissociation of the chemical bonds formed during the absorption process. Additionally, it generates a vapor phase that serves as the stripping medium. The overhead condenser condenses the vapor, providing a reflux stream that enhances internal liquid-vapor contact and contributes to maintaining product purity. The solvent regeneration process is responsible for the bulk energy penalty in the chemical absorption-based carbon capture processes [20].

MEA-based systems represent the benchmark technology for CO₂ capture in coal-fired power plants, owing to their high efficiency in treating flue gas streams with low CO₂ partial pressures. Such systems can reach recovery rates of up to 98%, and >99 vol% product purity. Most commercially available carbon capture systems are usually based on the use of MEA, MDEA or sterically hindered amines. This technology is well-established across various industrial sectors and can be retrofitted into certain existing power generation facilities. Its primary advantages include the low cost of MEA and the ability to achieve high CO₂ recovery efficiencies along with exceptional product purity. However, these technologies also suffer from some disadvantages such as;

-

Must treat large flue gas volumes with low CO₂ concentration.

-

High energy penalty for solvent regeneration

-

Low boiling point of MEA results in solvent carryover into the CO₂ capture and solvent regeneration steps.

-

CO₂ and NO_x present in the gas stream react with the amine to form heat-stable salts, which are non-regenerable under standard solvent regeneration conditions.

-

Hot flue gas causes solvent degradation which decreases absorber efficiency [11].

At TRL 9–11, amine-based chemical absorption represents the most advanced CO₂ separation technique. This methodology has been extensively deployed for decades and remains in active use across a broad spectrum of small- to large-scale projects globally, including applications in power generation, fuel processing, hydrogen production, and steel manufacturing. All commercial CCS plants currently in operation using amine-based absorption technology are listed in

Table 2. Amine-based large-scale commercial CO₂ capture facility currently in operation [17].

Operation Year	Location	Project	Industrial Operation	Separation/Capture Technology	CO2 Capture Capacity (Mt/Year)
2020	Redwater, AB, Canada	Alberta Carbon Trunk Line (ACTL) with Nutrien	Fertilizer production	Solvent-based chemical absorption, inorganic, Benfield process	0.3
2019	Barrow Island, Australia	Gorgon Carbon Dioxide Injection	Natural gas processing	Absorber and stripper system and an amine-based solvent	4
2018	Jilin, China	Jilin oilfield CO2- EOR	Natural gas processing	Solvent-based chemical absorption, amine.	0.6
2017	Illinois, US	Illinois Industrial Capture and Storage Project	Ethanol production	-	1.1
2017	Houston, US	Petra Nova Carbon Capture Project	Coal gasification	Amine (Econamine FG Plus)	1
2016	Abu Dhabi	Al Reyadah	Iron and steel production	Amine	0.8
2015	Alberta, Canada	Quest carbon capture and storage	Hydrogen production from natural gas	Solvent-based chemical absorption—Amine	1.0
2015	Al Hofuf, Saudi Arabia	Uthmaniyah CO2 EOR Demonstration Project	Natural gas processing	Solvent-based chemical absorption, amine.	0.8
2014	Saskatchewan, Canada	Boundary Dam	Power generation from coal gasification	Amine based solvent	1.0
2008	Hammerfest, Norway	Snohvit	Natural gas processing	Amine	0.7
2008	Midale, Canada	Weyburn-Midale CO2 Project	Synthetic natural gas from Coal gasification	-	3.0
1996	North Sea, Norway	Sleipner	Natural gas processing	Amine	1.0
1982	Oklahoma, US	Enid Fertilizer CO2-EOR Project	Fertiliser production	Solvent-based chemical absorption—Benfield process.	0.7

.

Ammonia

Ammonia-based CO₂ capture has garnered significant interest due to its distinct advantages, including high capture efficiency, reduced capital expenditure, and operational simplicity [21]. This technology is recognized as a mature solution within the gas processing industry for the treatment of acid gases such as CO₂ and SO_x. However, a key barrier to the widespread adoption and commercialization of aqueous ammonia-based CO₂ capture systems is ammonia slip, which arises from ammonia’s inherently high volatility. Commercially available ammonia-based CO₂ capture systems include the following:

-

Alstom Chilled Ammonia Capture (CAP) Process (Tennessee, USA and Mongstad, Norway)

-

Powerspan ECO₂ Ammonia-Based Capture Process (Ohio, USA).

-

CSIRO (Commonwealth Scientific and Industrial Research Organization) ammonia-based CO₂ capture process (Munmorah Power station, Australia).

-

KIER (Korea Institute of Energy Research) ammonia-based CO₂ capture technology (Daejeon, Republic of Korea).

-

RIST (Research Institute of Industrial Science & Technology) CO₂ capture process (Posco, Republic of Korea).

Tsinghua University in China and the Norwegian University of Science and Technology (NTNU) in Norway have developed noble ammonia-based CO₂ capture technology [22,23]. The reaction mechanism of CO₂ capture using ammonia has been known to the scientific community for many years, and a detailed review of the method and its chemistry can be found in Han et al. [22] and Augustsson et al. [24].

The power company Alstom is one of the leading groups worldwide in the development of the Chilled Ammonia Process (CAP) [22]. General Electric has further developed the technology [24]. In this approach, the flue gas is cooled down to low temperatures, preferably below 10 °C. Treated with a high concentration ammonia solution (~28 wt.%), the exhaust gas from the power plant reacts to form a slurry of ammonium salts such as ammonium bicarbonate according to reaction (3).

(NH₄)₂CO₃ + CO₂ + H₂O → 2NH₄HCO₃

(3)

Ammonia-based wet scrubbing systems exhibit operational similarities to conventional amine-based absorption processes, particularly in terms of gas-liquid contact dynamics and column design [25]. The process configuration closely resembles the schematic presented in Figure 7 for conventional amine-based scrubbing systems. CO₂ is absorbed in a contactor where it reacts with ammonia to form ammonium carbonate and bicarbonate salts, which are subsequently directed to a regeneration column where thermal energy is applied to release a concentrated CO₂ stream [24]. Ammonium bicarbonate partially crystallizes within the absorber, precipitating as a solid-phase product under the existing operating conditions. This crystallization process promotes the system’s CO₂ absorption capacity, i.e., drives forward reaction (3) according to Le Chatelier’s principle. If the absorption/desorption cycle is controlled in a way that mainly cycles ammonium bicarbonate and ammonium carbonate, the energy penalty for solvent regeneration can be up to 30% lower of that required by MEA-based systems. A qualitative comparison between amines and ammonia as CO₂ capture absorbents is summarized in

Table 3. Qualitative comparison between ammonia and amine-based CO₂ capture technologies [22].

Parameters	Amines	Ammonia
CO2 capture capacity	0.5 mole of CO2 per mole of MEA	1 mole of CO2 per mole of ammonia
Regeneration energy	4.0 Gj per ton of CO2	<2.0 Gj per ton of CO2
Absorption/regeneration rate	Faster	fast
Volatility	low	High
Thermal degradation	Severe	Negligible
Corrosiveness	Vulnerable	Resistant
Chemical stability	Forms heat stable salt	Stable
Absorbent cost	Expensive	Cheap

.

In addition, the reaction between ammonium bicarbonate and CO₂ has significantly lower heat of reaction than that of amine-based systems, resulting in significant energy savings. Moreover, ammonia-based absorption systems are tolerant to oxygen in the flue gas, which is instead problematic in amine-based systems causing corrosion, solvent degradation and oxidation to carboxylic acid and heat-stable amine salts [11]. A major drawback of ammonia-based systems is the higher volatility of ammonia compared to MEA. This results in the slipping of ammonia into the exit gas. Another disadvantage is the need to keep the absorber temperature below the decomposition temperature of ammonium bicarbonate (<60 °C).

Ionic Liquids

Ionic liquids (ILs) are typically defined as salts composed entirely of ions that remain in the liquid state at temperatures below 100 °C [20]. The use of ILs as solvents can offer numerous advantages over conventional amine-based CO₂ capture method, ranging from lower energy demand for solvent regeneration, to lower solvent volatility, lower vapor pressure, non-flammability, thermal stability and ease of recycle. An attractive feature of ILs is that they can be customized for specific needs based on the characteristics of flue gases. One of the most commonly proposed uses of ILs is in pressure swing configurations where CO₂ is preferentially absorbed from other gases and desorbed easily from the IL by depressurizing with no loss of solvent [20]. It has been estimated that using ILs in CO₂ capture can reduce the energy demand by as much as 16% relative to a MEA-based solvent [26]. A comparison between ILs and functionalized ILs and other conventional solvents in CO₂ capture methods is presented in

Table 4. Comparison of ILs and functionalized-ILs compared to conventional CO₂ capture process. (Adopted and modified from [27,28,29]).

Variables	Conventional ILs	Functionalized ILs	Amine (30% wt)	DEPG (Selexol Process)
Absorption type	Physical	Chemical	Chemical	Physical
Viscosity (cP)	20–2000	50–2000	18.98	5.8
Vapor pressure (bar) at 25 °C	1.33 × 10−9	1.33 × 10−9	8.5 × 10−4	9.73 × 10−7
ΔHabs (kJ/mol CO2) at 1 bar and 40 °C	~10–20	~40–50	~85	~14.3
CO2 solubility (mol/mol) at 1 bar and 20–40 °C	>2.51	1.6	0.50	3.63

.

Blanchard et al. [30] pioneered the use of ionic liquid (1-butyl-3-methylimidazolium hexafluorophosphate, [BmIm][PF6]) for CO₂ capture. Since then, extensive research has investigated the use of both conventional and functionalized ILs, e.g., Tong et al. [31], Lotto et al. [32], Chaudhary et al. [33], Voskian et al. [34], Thakur et al. [35], Zhao et al. [36], Wang et al. [37], Aki et al. [38], Pérez-Salado Kamps et al. [39]. As well, Sood et al. [35], Zheng et al. [40], Shukla et al. [41], Aghaie et al. [27], El-Nagar et al. [42], Inyang et al. [43] extensively reviewed ILs applications in carbon capture. A wide variety of ILs have been investigated in CO₂ capture. Among them, the imidazolium class is the most widely investigated and reported in the literature [44]. In addition to imidazolium based ILs, phosphonium, pyridinium, and pyrrolidinium based ILs were also investigated [27]. These types of ILs can be classified as conventional ILs. Extensive research established that the solubility of ILs increases with the length of the alkyl side chain on the imidazolium ring in the cations of the ionic liquid [28], but also that it is usually the basicity of the anion playing a major role in CO₂ adsorption, whereas the cation plays a minor role [41,45,46]. One major advantage of ILs is their selectivity towards CO₂ compared to other gases such as CH₄, C₂H₄, C₂H₆, CO, NO, O₂, H₂, N_2. Another advantage lies in the facile regeneration of the solvent by a thermal or pressure swing process. However, using ILs in capturing CO₂ from flue gas from coal or natural gas-fired powerplants is not feasible due to the low partial pressure of CO₂. Therefore, task specific or functionalized ILs were developed with both chemisorption and physisorption properties so as to overcome this drawback.

Although significant advances in the use of ILs in CO₂ capture have been made in the last two decades, this technology is still far from being adopted and used in the industry. Long-term stability and adsorption behavior of ILs under practical conditions need further investigation for the realization of this technology at scale. This compounds other existing challenges to ILs-based CO₂ capture technology, which include the lack of suitable equipment, of techno-economic assessments, process scale-up vis-a-vis the high viscosity of ILs, cost, availability, compatibility with the exhaust gas and the purity of ILs [28]. In order to commercialize CO₂ capture technology with ILs, it is necessary to find economical but suitable IL/additive mixtures with a relatively high solubility and selectivity for CO₂ by rigorously studying key mass transfer and thermodynamic profiles of CO₂/H₂O/IL/additive systems [27].

4.1.2. Calcium Looping (CaL)

Calcium looping (CaL) has emerged in the last decades as a promising technology for CO₂ capture [47,48]. It has gained attention due to its potential to be integrated into future energy facilities, as well as for retrofitting existing ones. As a hybrid technology between the post combustion and oxyfuel combustion technologies, calcium looping is deemed to have high potential for capturing CO₂ from cement production plants [49] and fossil-fuel based power plants [48]. In addition to the application in cement factories and power plants, CaL has already been applied in Enhanced Oil Recovery (EOR) and hydrogen production [50]. The use of lime for removing CO₂ from hot gases is a 100-year-old practice, however, the idea of using it in a reversible scheme to capture CO₂ from flue gases is relatively new [47,51]. The CaL process depends on the multicycle calcination-carbonation of CaCO₃ (Equation (4)), which is the second most abundant material on earth.

CaCO_3(s) ⇄ CaO_(s) + CO_2(g)   ΔH⁰_r = 178 kJ/mol

(4)

In a standard cycle, the CO₂ from the flue gas is captured using CaO, which is previously obtained from limestone calcination, to produce CaCO₃ by carbonation at high temperature (~650 °C). The carbonated stream of solid leaving the carbonator is then sent to the calciner where the CaCO₃ is decomposed to form CaO-rich sorbent. The energy required in the calciner is provided by burning fuel under oxyfuel conditions at temperature around 900 °C. The CO₂ produced by oxyfuel combustion in the calciner, and the CO₂ released from the decomposition of CaCO₃, are then combined in the form of a concentrated gas stream ready to be cooled down, purified and compressed for storing [49]. In recent decades, research on CaL development focused primarily on its application in power plants and in cement factories. As a result, CaL for these applications has advanced rapidly to TRL 6–7 and has been tested in several pilot plants, both in power generation and cement manufacturing, as presented in

Table 5. Current CaL-based demonstration/research project for CO₂ capture.

Operation Year	Location	Project Name	Industrial Operation	Status/Notes	Refs.
2014–2017	Technische Universität Darmstadt, Germany	SCARLET EU project 2014	Power plants	Demonstration of successful operation and process optimization for scaling up to a 20 MWth pilot plant	[48,52]
(2015–2018)	15 EU participant Coordinated by SINTEF ENERGY AS, Trondheim, Norway	CEMPCAP EU project, 2015	Cement production	The project aimed to leverage TRL 6 for CaL in cement industry with 90% capture rate	[48,53]
2017–2022	13 EU participant coordinated by Laboratory of Energy and Environment of Piacenza—LEAP scarl, Piacenza Italy.	CLEANKER EU project, 2017	Cement production	CLEANKER aims at demonstrating CaL at TRL > 7	[48]
2016–2019	7 EU partner coordinated by INESC TEC, Portugal.	FlexiCaL EU project, 2016	Coal based power plants	Two process options were tested on a pilot-scale: a highly load-flexible plant concept and an energy storage system using CaO/ CaCO3 silos.	[48]
2016–2020	14 industrial, technology and research & development partners across EU coordinated by CALIX-EUROPE, France	LEILAC EU project, 2016	Lime and cement production	Based on the use of an entrained flow reactor for efficient capture of CO2 from lime and cement production.	[48,54]

. In principle, CaL could be used as a standalone post combustion system retrofitted to the exiting cement or power plant without any integration step (Figure 8 and Figure 9). Arias et al. [49] studied post-combustion CO₂ capture from cement plants. In this instance, a 30-kWh pilot plant retrofitted to operate with the higher carbonator CO₂ load displayed high capture efficiency (close to the limit allowed by the equilibrium) when using small particle size sorbent. In turn, the use of small particle size materials resulted in a lower inventory of solids in the carbonator (75 kg/m²) at typical gas velocities (2.5 m/s). These results indicate that CaL technology can be retrofitted to cement industry plants based on the knowledge acquired through studies on CaL in more developed systems such as power plants.

Several studies have explored the integration of the CaL process with Thermochemical Energy Storage (TCES) systems in renewable power plants—particularly in concentrated solar power (CSP) facilities—to enhance system dispatchability and energy flexibility. In this type of integration, solar thermal energy is used to drive the decomposition of calcium carbonate (CaCO₃) in a solar calciner, following the reaction (4). After decomposition, the resulting calcium oxide (CaO) and carbon dioxide (CO₂) are stored separately. When energy is required, calcium oxide (CaO) reacts with carbon dioxide (CO₂) at high temperatures (above 650 °C) in the carbonator, releasing stored thermal energy and forming calcium carbonate (CaCO₃) [48,55]. Numerous laboratory-scale experiments are being conducted to evaluate the integration of the Calcium Looping (CaL) process with TCES systems, with a primary focus on enhancing reaction kinetics [56,57,58,59,60].

CaLis expected to play a significant role in next-generation post-combustion CO₂ capture technologies, as it faces no major technical barriers to full-scale commercialization. Retrofitting a CaL process into existing coal-fired power plants and in the cement, industry is seen as a technically feasible and economically attractive option. However, more research is needed to advance the technology from current TRL 6 to 8, which implies reaching commercial demonstration at full scale. On the other hand, the Cal-CSP technology is still at a lower level of maturity, where current research efforts aim to reduce the technological risks progressing from TRL-4 (technology validated in the lab) to TRL-5 (technology validated in a relevant environment) [48].

4.1.3. Chemical Looping

Chemical looping combustion (CLC) is a promising CO₂ capture technology with high capture efficiency and low energy penalty [61]. Lewis et al. [62] conducted the first study to produce pure CO₂ from gaseous fossil fuels. Ishida et al. [63] further developed the CLC method for climate mitigation. In the CLC process, fine metal particles called “oxygen carriers (OC)” are used to transfer oxygen between two reactors, called air reactor and fuel reactor, respectively. Oxygen carriers are usually oxides of transition metals such as Cu, Cd, Ni, Mn, Fe, Co. The oxygen carriers extract oxygen from air in one reactor and transfer it to the fuel in the next reactor. The oxidized oxygen carrier (MeO_a) is supplied to the fuel reactor to oxidize the fuel, according to Equation (5).

(2n + m)Me_xO_y + C_nH_2m ⇄ nCO₂ + mH₂O + (2n + m)Me_xO_y−1

(5)

The oxidized oxygen carrier is reduced to metal or to a lower oxidation state (Me/MeO_a−1). The reduced oxygen carrier is then sent to the air reactor to be oxidized into its original form, where oxygen is extracted from air according to reaction (6).

Me_xO_y−1 + 1/2O₂ ⇄ Me_xO_y

(6)

Thus, a continuous chemical combustion loop occurs between pure oxygen and fuel (Figure 10). Since the fuel does not come into direct contact with air, the combustion products consist solely of CO₂ and water vapor. This allows for the production of a high-purity CO₂ stream by simply condensing the water [64]. One of the key advantages of CLC is its inherent ability to capture CO₂ without the need for additional energy-intensive separation processes. Another benefit is the significantly reduced formation of nitrogen oxides (NO_x), due to the lower operating temperatures in the air reactor. However, CLC also presents challenges, including the need for two separate reactor vessels and the continuous circulation of solid materials between them. Additionally, the exhaust gases are typically at lower temperatures and pressures than those found in conventional gas turbine systems, which can limit energy recovery efficiency.

The oxygen carrier (OC) is the core component of a CLC system, playing a critical role in enabling the combustion process. The role of the oxygen carrier (OC) is to transport oxygen from the air to the fuel. To perform this function effectively, it must exhibit high reactivity with both air and fuel. The three main properties that OCs need to possess are: high reactivity, durability and fluidizability. While pure metal oxides possess the desired reactivity, they are often combined with support materials to enhance their stability, mechanical strength, and overall performance. A summary of commons OCs is presented in

Table 6. Operating condition and performance of common OCs.

Oxygen Carrier (OCs)	Melting Temperature (°C)	Support Materials	Maximum Oxygen Transport Capacity (Ro,max)	Refs.
Ni-based	1455	Yttria-stabilized-Zirconia (YSZ), Al2O3, NiAl2O4, MgAl2O4, oxides of Si, Ti, Zr	0.214	[61,64]
Cu-based	1085	Al2O3 and SiO2	0.201	[61,64]
Fe-based	1538	Al2O3 and MgAl2O4	0.1	[61,64]
Mn-based	1246	ZrO2	0.101	[61,64]

.

Several experimental studies [65,66,67,68,69] have shown that CLC technology applied to gaseous fuels offers satisfactory performance in terms of conversion rate, total oxygen demand, and capture efficiency. A key challenge is the gradual loss of oxygen carrier reactivity over repeated cycles, which leads to a decline in overall system performance over time. In addition, modified oxygen carriers were also widely used for gaseous fuels. To date, nickel-based oxygen carriers are the dominant type, showing high performance with excellent stability [61].

Although the major advances to date in CLC have been obtained in applications for CO₂ capture from gaseous fuel, more recently CLC technology applications have expanded to liquid and solid fuels as well. Solid fuel combustion takes place in two stages, where the loss of volatile matter occurs at the first stage, and combustion of the remaining char and coke occurs at the second stage. When CLC is applied to gaseous fuels, it is relatively easy to envisage the interaction between gaseous volatile matter and the sold oxygen carrier. However, when using CLC with solid fuels, the solid-solid interaction, i.e., combustion of the solid fuel with a solid oxygen carrier is more challenging. Regardless of the difficulties in understanding solid-solid phenomena, a significant interaction between gas phase gasification products and the solid oxygen carrier in these systems is known to occur. For example, gasification of solid fuel in a fluidized reactor with steam or CO₂ will lead to the production of CO and H₂ which can be combusted by the oxygen carrier as presented in Equations (7) and (8) [47].

$$\mathrm{C}+{\mathrm{H}}_2\mathrm{O}\rightleftarrows \mathrm{C}\mathrm{O}+{\mathrm{H}}_2$$

(7)

$$\mathrm{C}\mathrm{O}+{\mathrm{H}}_2+2{\mathrm{M}}_{\mathrm{e}}\mathrm{O}\rightleftarrows {\mathrm{H}}_2\mathrm{O}+\mathrm{C}{\mathrm{O}}_2+2{\mathrm{M}}_{\mathrm{e}}$$

(8)

The overall rate of solid fuel conversion is kinetically constrained by the gasification step, which constitutes the rate-limiting stage in the reaction sequence. There are two important features relevant to chemical looping for solid fuel combustion. The first one is the large difference in reactivity between different kinds of chars, and the second one is the effect of product inhibition. Indeed, the gasification reaction rate is slower in the presence of H₂ and CO products (reaction 7). Therefore, in the presence of a solid oxygen carrier, which sequesters the reaction 7 products (reaction 8), the overall solid fuel gasification process is accelerated. There are two strategies to overcome the low reactivity of char. One approach involves the physical segregation of char from the oxygen carrier using carbon strippers, while an alternative strategy enhances the char conversion rate through Chemical Looping Oxygen Uncoupling (CLOU) combustion [47].

Extensive research efforts have advanced CLC from laboratory-scale experiments to pilot-scale demonstrations, enabling the investigation of material reliability and durability under prolonged operational conditions. Recently, large-scale demonstrations (

Table 7. Large-scale demonstration plant for CLC using different fuel and oxygen carriers.

Project and Location	Fuel	Oxygen Carrier	Plant Capacity	Ref.
Technische Universität Darmstadt, Germany	Hard coal	Ilmenite	1 MWth	[70]
Alstom	Coal	Limestone	3 MWth	[71]
The Ohio State University	Bituminous and lignite coal	Iron-based	25 kWth	[72]
Chalmers University of Technology, Sweden	Natural gas	Calcium manganite	10 kWth	[73]
Korea Institute of Energy Research	Natural gas and syngas	-	200 kWth	[61]
Chalmers University of Technology, Sweden	Biomass	Manganese and ilmenite	4 MWth	[74]

) have shown promise for the use of CLC capture technology in power and hydrogen production plants.

4.2. Physical Separation

CO₂ separation by physical means is based on adsorption, absorption, cryogenic separation, dehydration, and compression. In physical adsorption processes, solid sorbents such as activated carbon, alumina, metal oxides, and zeolites are employed to selectively capture CO₂ from gas mixtures via weak van der Waals interactions. On the other hand, liquid solvent such as Selexol or Rectisol is used to absorb CO₂. The CO₂ captured onto a solid adsorbent can be subsequently released by increasing either the temperature, pressure, or by creating vacuum, which are known as temperature swing adsorption [TSA], pressure swing adsorption [PSA] or vacuum swing adsorption [VSA] respectively [5]. At the moment, physical separation is used specifically in natural gas processing, and ethanol, methanol and hydrogen production facilities.

4.2.1. Physical Adsorption

In the early 1990s, physical adsorption was considered a viable alternative to chemical absorption-based CO₂ capture. Substantial research has focused on the development of high-performance adsorbent materials with enhanced selectivity and resistance to contaminant-induced degradation. To date, different types of adsorbent materials, from classic (carbon-based material, alumina, silicas, zeolites) to functionalized (metal organic frameworks, hydrotalcites, amine supported adsorbents, polymers, high temperature metal-oxides) have been explored for their application in CO₂ capture [47].

Adsorption-based CO₂ capture is an attractive technology in that it can be retrofitted to any existing power plant, and because it can operate at a wide range of temperature and pressure conditions, which can meet the operating requirements of both pre- and post-combustion processes. In addition, adsorption-based CO₂ capture is particularly attractive in direct air capture applications, due to the low CO₂ concentration in the air stream. Another advantage of adsorption-based CO₂ capture lies in its relatively low environmental impact, especially when compared to amine-based solvent systems, which are prone to thermal and oxidative degradation, leading to the formation of toxic and corrosive byproducts. Below we summarize the use of different adsorbents for CO₂ capture, focusing their main attributes, strengths, and weaknesses, including the state-of-the-art of development.

Carbon-Based Adsorbent

Carbon-based adsorbents are appealing due to their inexpensive and large surface area that can readily adsorb CO₂. Different types of carbon-based products such as low-cost pyrogenic carbon material (e.g., charcoal, biochar), activated carbon, carbon molecular sieves, aerogels, and carbon-based nanomaterials (e.g., graphene, carbon nanotube) are in principle available for use in this technology. The adsorption of CO₂ in these materials is based on physisorption. Therefore, high porosity is the pre-eminent property of these materials for CO₂ capture applications [75]. The CO₂ capture performance of different types of carbon-based adsorbent is summarized in Table 8 [76]. Activated carbon is one of the well-developed adsorbents for CO₂ capture which is extremely porous with large internal surface area. Among all the carbon-based adsorbents, activated carbon with its high porosity and large internal surface area, is amongst the best-developed adsorbents for CO₂ capture, and has reached industrial maturity [47]. Due to its hydrophobic nature, activated carbon is not greatly affected by moisture, although adsorption capacity was found to decrease marginally compared to the dry adsorbent. In addition, activated carbon shows high thermal stability, favorable adsorption kinetics, a wide range of precursor materials for activated carbon production, and large adsorption capacity at high temperature. Some drawbacks of activated carbon include low adsorption capacity at mild conditions, and/or in the presence of NO_x and SO_x which negatively affect the performance [11].

Different carbon-based adsorbents are produced at different conditions. They also show different adsorption capacity at different conditions. Among carbon-based nanomaterials such as graphene, graphene oxide, and carbon nanotubes (CNTs), activated carbons remain the most cost-effective option. According to the data presented in Table 9, the average adsorption capacity of activated carbon is almost double that of nanomaterial-based adsorbents. Hence, activated carbon has the higher potential for use in CO₂ capture [76].

Table 8. Performance of CO₂ capture by carbon-based material at atmospheric pressure and temperature.

Carbon-Based Materials	Note on the Carbon Material	BET Surface Area (m2/kg)	Adsorption Capacity (mmol/g) at 298 K	Ref.
Biochar	Biochar derived from pine nutshell using KOH as activating agent	1486	5	[77]
Graphene	Reduced graphene oxide	1300	2.45	[78]
CNTs	Double-walled CNTs	423	3.5	[79]
Activated carbon	N and S-doped Activated carbons	2040	5.19	[80]
Microporous carbon	N-doped microporous carbon with pore size < 2 nm	1060	4.24	[81]
Mesoporous carbon	Pore size in between 2–50 nm	3934	2.8	[82]
Hierarchical Carbon	Consist of micro, meso and microporous carbon	2698	3.7	[83]

Table 8. Performance of CO₂ capture by carbon-based material at atmospheric pressure and temperature.

Carbon-Based Materials	Note on the Carbon Material	BET Surface Area (m2/kg)	Adsorption Capacity (mmol/g) at 298 K	Ref.
Biochar	Biochar derived from pine nutshell using KOH as activating agent	1486	5	[77]
Graphene	Reduced graphene oxide	1300	2.45	[78]
CNTs	Double-walled CNTs	423	3.5	[79]
Activated carbon	N and S-doped Activated carbons	2040	5.19	[80]
Microporous carbon	N-doped microporous carbon with pore size < 2 nm	1060	4.24	[81]
Mesoporous carbon	Pore size in between 2–50 nm	3934	2.8	[82]
Hierarchical Carbon	Consist of micro, meso and microporous carbon	2698	3.7	[83]

Zeolites

Zeolites are microporous crystalline aluminosilicates composed of a three-dimensional framework of interlinked SiO₄ and AlO₄ tetrahedra, featuring uniform pore sizes typically ranging from 4 to 15 Å and specific surface areas between 200 and 500 m²/g [47,75,84]. Both natural and surface-functionalized zeolites have been extensively utilized in gas separation and purification applications due to their tunable pore structures and high selectivity. Separation of gases by zeolite adsorbents occurs through the molecular sieving effect when they pass through these materials. An additional gas separation mechanism by zeolites is through selective adsorption of gases with large energetic dipole and quadrupole moments. Due to its high quadrupole moment, CO₂ exhibits strong electrostatic interactions with the electric fields generated by the framework cations within zeolites. The efficiency of CO₂ separation using zeolites is primarily influenced by the framework structure and composition, the nature and distribution of exchangeable cations, material purity, molecular size and geometry, as well as the polarity of the target species [84]. Moreover, the presence of dual cation sites—where CO₂ can simultaneously interact with two adjacent cations—has been shown to enhance adsorption affinity. Overall, zeolites exhibit high CO₂ uptake capacities, with synthetic variants such as zeolite 13X demonstrating superior adsorption performance compared to their natural counterparts. However, the presence of impurities (NO_X, SO_X and H₂O) can significantly impact performance and represents a major drawback in the use of zeolites for CO₂ capture [12]. Gonzalez-Olmos et al. [85] have conducted comparative analyses between zeolite-based and carbon-based adsorbents through a life cycle analysis (LCA) study. It was found that a specific zeolite (13X-APG) has 13% lower environmental loads compared to carbon molecular sieve (CMS-330) when used in vacuum pressure swing adsorption.

Metal Organic Frameworks (MOFs)

Metal–Organic Frameworks (MOFs) represent an emerging class of porous solid sorbents with significant potential for CO₂ capture applications [86]. MOFs are solid networks of metal ions or metal cluster vertices linked by organic spacers [84]. Their synthesis usually involves a self-assembly process of metal ions and organic ligands. Because of their extraordinary surface areas and pore volumes, MOFs have shown excellent CO₂ adsorption capacities at pressure above 1 bar. Usually, the interaction between adsorbed CO₂ and the adsorbent is weak, with CO₂ starting to desorb at temperatures higher than 30 °C [75]. The adsorption of CO₂ in MOFs occurs via the interaction between CO₂ and open metal sites, and/or the interaction between CO₂ and functional groups present in the MOFs [47].

Enhancing CO₂ uptake efficiency in MOFs necessitates the strategic functionalization of the framework to increase its affinity toward CO₂ molecules. Common MOFs functionalization involves the use of nitrogen bases. Three principal categories of nitrogen-functionalized MOFs have been synthesized: (i) heterocyclic derivatives such as pyridine-based ligands, (ii) aromatic amine derivatives including aniline functionalities, and (iii) alkylamine-functionalized frameworks incorporating groups like ethylenediamine [84]. The improved CO₂ adsorption capacity of nitrogen base-functionalized MOFs arises from the strong electrostatic interactions between the quadrupole moment of CO₂ and the localized dipole fields introduced through heteroatom incorporation within the framework. In addition to nitrogen base-functionalized MOFs, organic linkers with functional groups containing other heteroatoms have also been examined, including OH^•, −NO₂, CN, X. In all cases, the CO₂ adsorption capacity of MOFs is governed by the degree of ligand functionalization and the polarizing strength of the incorporated functional groups [84].

Cost is one major challenge in the adoption of MOFs at industrial scale and for technology commercialization. The synthesis of MOFs incurs significantly higher costs due to the expensive precursor materials required, especially when compared to conventional adsorbents such as zeolites and activated carbons. Significant research to date has focused on lowering MOFs CO₂ capture costs by improving their hydrothermal stability and by increasing adsorption capacity [87]. A comparison between different physical adsorbents is presented in Table 9.

Table 9. Comparison between different physical adsorbent for carbon capture.

Adsorbent Type	Adsorption Temperature (K)	Regeneration Temperature (K)	Adsorption Pressure (atm)	Adsorption Capacity (mmolg−1)	Ref.
Activated carbon	295		1	5.19	[84]
Zeolite 13X	295	473	1	4.61	[88]
MOFs (MOF-74(Mg))	313		0.15	5.5	[89]
K2CO3	323	423	1	6.89	[75]
Na2CO3	323	423	1	0.66	[90]

Table 9. Comparison between different physical adsorbent for carbon capture.

Adsorbent Type	Adsorption Temperature (K)	Regeneration Temperature (K)	Adsorption Pressure (atm)	Adsorption Capacity (mmolg−1)	Ref.
Activated carbon	295		1	5.19	[84]
Zeolite 13X	295	473	1	4.61	[88]
MOFs (MOF-74(Mg))	313		0.15	5.5	[89]
K2CO3	323	423	1	6.89	[75]
Na2CO3	323	423	1	0.66	[90]

4.2.2. Cyclic Adsorption Processes

Adsorption processes using solid sorbents consist of two main steps: adsorption and desorption. The technical viability of the process is governed by the adsorption step. Conversely, the desorption step predominantly dictates the energy demand and economic viability of the overall process. For instance, the higher the affinity of a gas component towards a sorbent, the higher the energy required for regeneration of the sorbent. The primary advantages of physical adsorption over chemical or physical absorption lie in its operational simplicity and lower energy requirements. The development of cyclic adsorption processes has helped increase the commercialization potential of adsorption technology at scale. The cyclic adsorption process is now a relatively mature technology that is already applied on a commercial scale for carbon capture [47]. Depending on the desorption techniques employed, cyclic adsorption processes are classified as Temperature Swing Adsorption (TSA) and Pressure Vacuum Swing Adsorption (PVSA). In the following section, each of these processes is briefly discussed.

Vacuum Swing Adsorption (VSA) or Pressure Swing Adsorption (PSA) is a widely used sorbent regeneration approach, which exploits pressure differentials. VSA is also referred to as Pressure Vacuum Swing Adsorption (PVSA) when the adsorber feed stream is partially pressurized [47]. VSA is more suitable than PSA for post combustion CO₂ capture, since pressurization required in PSA makes the process uneconomical [91]. Zeolites and activated carbons are widely used adsorbent materials for VSA applied to fixed bed reactor configurations. When a single VSA system is used, a significantly deep vacuum level is required to achieve higher levels of CO₂ product purity. PVSA will be a viable alternative where different adsorbents can be used at different stages, depending on the type of feed gas stream. Wang et al. [92] demonstrated a two-stage PVSA system for CO₂ capture from flue gas in a coal-fired power plant, incorporating a dehumidification unit to enhance process efficiency. Two PVSA units were used, with zeolite 13X as adsorbent in the first unit, and activated carbon in the second unit. In this system, 90.2% CO₂ was recovered with 95.6% purity. Power consumption amounted to 2.44 MJ/kg of CO₂ captured. Overall, PVSA seems to offer an attractive pathway for reducing cycle time and maximizing efficiency in adsorption-based CO₂ capture processes.

Temperature Swing Adsorption (TSA) has been industrially implemented for the removal of trace concentrations of CO₂ and moisture from air streams in Air Separation Units (ASUs). However, application of TSA in the removal of bulk CO₂ is not yet mature [47]. TSA is used either in direct mode, using a hot stream consisting of CO₂ and steam directly as purge gas, or in indirect mode, where external heat is used to regenerate the adsorbent. Current research focuses on the reduction of overall heat requirements by pursuing the development of sorbent materials with elevated adsorption capacity and reduced specific heat capacity [91,93,94,95]. By incorporating additional purge and recycle stages, along with intermediate heating steps, TSA systems can achieve high-purity CO₂ recovery at elevated capture efficiencies. One major drawback of the TSA process is the need for an additional dehumidification step since the prototypical TSA adsorbent (13X zeolite) is susceptible to moisture. The dehumidification step requires an additional 2–3 GJ of energy per ton of CO₂ sequestered [96], which makes it too costly for large scale applications. However, this limitation can be overcome by using hydrophobic adsorbents [47,91].

Electrical Swing Adsorption (ESA) is another attractive pathway to reduce the solvent regeneration energy penalty of adsorption-based CO₂ capture. This process involves rapid thermal or Joule heating of the adsorbent by passing an electric current through a conductive medium, which may either be the adsorbent itself or a conductor in direct thermal contact with it. This is a derivative of the conventional TSA mode; however, ESA enables faster heat transfer rate and better desorption kinetics compared to TSA since the heating occurs in-situ. In ESA, the adsorbent must be electrically conductive. Activated carbon fibers are considered a potentially viable sorbent material for ESA applications. One drawback of ESA is that can only be applied in a fixed bed configuration. This in turn requires long cooling times, which cancels out the advantage of fast in-situ heating that this approach offers. Another drawback of ESA is the use of electricity, which is costly compared to low-grade waste heat used in TSA.

Sorption Enhanced Water Gas Shift (SEWGS) utilizes high temperature adsorbents, such as CaO or potassium promoted hydrotalcite-based materials, to remove CO₂ which in turn drives forward the water-gas-shift reaction, thus maximizing hydrogen production [47]. The CO₂-saturated adsorbent material is regenerated using steam. SEWGS is particularly suitable for fossil-fuel based power plants. The European collaboration project FP7 developed the SEWGS process, further improving the energy of the process to 0.8–1.0 GJ per t CO₂. The novel ALKASORB+ adsorbent material developed in this study displays high efficiency and capacity that result in low CO₂ removal cost. Indeed, the SEWGS process can be up to 40% more economical than the traditional Selexol process [47]. A comparison of energy consumption between the different cyclic adsorption processes is highlighted in Table 10.

Table 10. Energy consumption in adsorbent regeneration of different cyclic adsorption processes.

Cyclic Adsorption Process	Regeneration Energy GJ/tonCO2	Ref.
VSA	2.64	[91]
PVSA	2.37	[91]
TSA	4.07	[91]
ESA	2.04	[47]
Hybrid (SEWGS)	1	[47]

Table 10. Energy consumption in adsorbent regeneration of different cyclic adsorption processes.

Cyclic Adsorption Process	Regeneration Energy GJ/tonCO2	Ref.
VSA	2.64	[91]
PVSA	2.37	[91]
TSA	4.07	[91]
ESA	2.04	[47]
Hybrid (SEWGS)	1	[47]

4.2.3. Physical Absorption

Physical absorption processes utilize a liquid solvent for capturing CO₂. Physical absorption of CO₂ on a substrate material is governed by temperature and pressure. For example, high CO₂ partial pressure and low temperature conditions increase a material’s absorption capacity. The absorption capacity primarily depends on vapor-liquid equilibrium according to Henry’s law, which in this scenario describes the virtual linear dependency between the partial pressure of CO₂ in the gas phase, and solvent loading (CO₂ dissolved, or absorbed) [97]. The absorption dependency on partial pressure can be beneficial for solvent regeneration. Physical solvents have been used to remove CO₂ and H₂S from the raw gases produced by oil and coal gasification [18]. Several physical absorption-based CO₂ capture processes are summarized in Table 11. We briefly discuss each of these processes below.

The Rectisol™ process employs refrigerated methanol as a physical solvent and has been extensively utilized for the purification of synthesis gas derived from coal gasification, particularly in ammonia production and Fischer–Tropsch synthesis applications. The process can remove CO₂ to ppm range. It is one of the most common syngas purification processes worldwide, accounting for 75% of all syngas produced globally. A major difference compared to other scrubbing processes is the operating temperature, which in the Rectisol process typically ranges between −15 °C and −60 °C [18]. After the desulfurization and water-gas shift reaction steps, the CO₂ concentration in the gas stream typically hovers at around 33% v/v. The gas stream is then cooled and fed into the CO₂ absorber containing refrigerated methanol [97]. The rich solvent is subsequently sent to the regeneration column where CO₂ is discharged by flash desorption at ca. 1 bar pressure [98].

The Selexol™ process, licensed by Universal Oil Products (UOP), is widely employed in the refining industry, natural gas sweetening, syngas treatment, and fertilizer production. It utilizes a solvent mixture composed of various dimethyl ethers of polyethylene glycol, typically represented by the formula (CH₃O(C₂H₄O)_nCH₃). In this process, flue gas is first dehydrated before entering the absorber, which operates at 30 atm and a temperature range of 0–5 °C. The CO₂-rich solvent is subsequently regenerated either by pressure reduction or by inert gas stripping [98].

The Purisol^TM process employs N-methyl-2-pyrrolidone (NMP) for CO₂ and H₂S removal from syngas. It is particularly well-suited and widely implemented in industry for the removal of CO₂ from off-gases with high carbon dioxide concentrations. Absorption occurs at 50 bar and at a temperature ranging from ambient to −15 °C. The regeneration of solvent occurs by stripping with an inert gas [98]. One major drawback for the Purisol process is the high volatility of the solvent, compared to that of other solvents. Due to this, water scrubbing of the gaseous effluent to avoid excessive solvent losses is required [97].

The Sulfinol^TM process uses a mixture of diisopropylamine (DIPA) or methyldiethanolamine (MDEA) and tetrahydrothiophene dioxide (SULFOLANE) in different ratios. This solvent has a high absorption capacity with low energy demand for solvent regeneration. Absorption occurs at 40 °C and 60–70 bar. Solvent regeneration is carried out by heating the solution to 110 °C under vacuum [98].

Fluor™ marked the first development of a physical absorption process specifically designed to extract CO₂ from natural gas streams. This process employs Propylene carbonate (C₄H₆O₃) as absorbent due to its much higher affinity for CO₂ vs. methane. The process occurs in a high-pressure absorber (30–80 atm) at temperatures below ambient. By means of pressure swing, the solvent is regenerated in a flash vessel at a lower pressure. This process has a major disadvantage: it requires the flue gas to be dehydrated before entering the absorber to prevent the formation of hydrates [97,98].

The Morphysorb^™ process is a relatively new process developed in 1997 jointly by the Gas Technology Institute and Uhde. After extensive lab, bench and pilot scale demonstration, the process found its first commercial application at the Kwoen processing facility close to Chetwynd, British Columbia, Canada. The Kwoen Plant was designed to handle 300 million standard cubic feet per day (MMscfd) of untreated natural gas at a pressure of 74 atmospheres. Raw natural gas contains H₂S and CO₂ (20–25%), which need to be removed prior to further processing. Through Morphysorb technology, the acid gas content is reduced by about 50%, and subsequently injected into an injection well. The Kwoen plant has been operating since August 2002 and was decommissioned in 2012 [99,100].

The Morphysorb process employs N-Formyl morpholine along with other morpholine derivatives as physical solvents. It is particularly well-suited for applications involving high pressures and elevated acid gas concentrations, offering significant reductions in both capital and operating costs.

Table 11. Summary of the physical absorption-based CO₂ capture processes.

Process	Solvent	Absorption Temperature (°C)	Pressure (Atm)	Advantage	Disadvantage	Refs.
RectisolTM	Methanol	−15–60	50	-Non-foaming solvent	-High regeneration cost	[97,98]
SelexolTM	Mixture of dimethyl ethers and polyethylene glycol	0–5	30	-Non-thermal solvent regeneration	-Most efficient at elevated pressure	[97,98]
				-Non-corrosive solvent
PurisolTM	N-methyl pyrrolidone	−15	50	-Non-foaming solvent	-High compression cost	[97,98]
				-High chemical and thermal stability	-Most efficient at high-pressure
SulfinolTM	Mixtures of diisopropylamine (DIPA) or methyldiethanolamine (MDEA) and tetrahydrothiophene dioxide (SULFOLANE) in different blends	40	60–70	-High capacity -Low solvent circulation rate	-Foaming issues	[97,98]
					-Corrosive solvent
					-Thermal regeneration
FluorTM	Propylene carbonate	<25	30–80	-High CO2 solubility	-High solvent circulation rates	[97,98]
				-Non-thermal regeneration
				-Simple operation	- Expensive solvent
				-Non-corrosive solvent
Morphysorb™	N-formyl morpholine (NFM) and N-acetyl morpholine (NAM) mixtures as solvent	−20–+40	10–150	-High solvent loading capacity	Not yet matured	[98]
				-Low energy requirement -Non-corrosive solvent
				-Low capital and operating costs

Table 11. Summary of the physical absorption-based CO₂ capture processes.

Process	Solvent	Absorption Temperature (°C)	Pressure (Atm)	Advantage	Disadvantage	Refs.
RectisolTM	Methanol	−15–60	50	-Non-foaming solvent	-High regeneration cost	[97,98]
SelexolTM	Mixture of dimethyl ethers and polyethylene glycol	0–5	30	-Non-thermal solvent regeneration	-Most efficient at elevated pressure	[97,98]
				-Non-corrosive solvent
PurisolTM	N-methyl pyrrolidone	−15	50	-Non-foaming solvent	-High compression cost	[97,98]
				-High chemical and thermal stability	-Most efficient at high-pressure
SulfinolTM	Mixtures of diisopropylamine (DIPA) or methyldiethanolamine (MDEA) and tetrahydrothiophene dioxide (SULFOLANE) in different blends	40	60–70	-High capacity -Low solvent circulation rate	-Foaming issues	[97,98]
					-Corrosive solvent
					-Thermal regeneration
FluorTM	Propylene carbonate	<25	30–80	-High CO2 solubility	-High solvent circulation rates	[97,98]
				-Non-thermal regeneration
				-Simple operation	- Expensive solvent
				-Non-corrosive solvent
Morphysorb™	N-formyl morpholine (NFM) and N-acetyl morpholine (NAM) mixtures as solvent	−20–+40	10–150	-High solvent loading capacity	Not yet matured	[98]
				-Low energy requirement -Non-corrosive solvent
				-Low capital and operating costs

4.2.4. Membrane Separation

Membrane separation processes are among the most promising methods for CO₂ capture, especially from coal-or natural gas-derived flue gas, because of their energy efficiency, low cost, ease of scale-up, and low environmental impact [101,102]. Research has shown that a two-stage membrane separation process is competitive with a conventional amine process [103]. Lindqvist et al. [103] have studied two polymeric membrane-based processes for multistage separation of CO₂ from cement plant to identify optimal membrane properties, the required number of stages, and the operating conditions for each stage. The study considered two types of membranes: a dense polymeric membrane with excellent permeation characteristics, and an ultra-thin facilitated transport membrane offering both high selectivity and high permeability. The net present values of cost and CO₂ avoidance cost of the membrane-based process were compared to those of an amine-based (MEA) capture system for a cement plant with a capacity of 0.7 MtCO₂/year. The membrane process demonstrated significantly lower capital costs (€32.6 million vs. €294 million) and CO₂ avoidance costs (€27/t vs. €55/t) than the MEA-based alternative. Xu et al. [101] explored a membrane-based separation process for multicomponent gas mixtures using spiral-wound membrane modules. Their objective was to optimize both membrane area and energy consumption in single-stage and multi-stage configurations. In the multi-stage setup, they found that using a membrane with low selectivity in the first stage followed by one with high selectivity in the second stage significantly reduced the required membrane area, albeit with a slight increase in energy consumption compared to employing high-selectivity membranes in both stages.

While research on the use of membrane separation for CO₂ capture has progressed in the past decade, the technology is still in too early a stage for commercialization. In particular, the lack of extensive field testing of membrane-based capture systems hinders progress towards commercialization. Scaling up membrane separation processes from lab-scale to pilot scale still faces challenges, mainly related to membrane separation performance and membrane lifetime. Consequently, recent advancements have concentrated on improving capture system energetics, process synthesis, membrane scale-up, modular fabrication, and field validation [104]. A few groups have scaled up membrane separation of CO₂ from laboratory to pilot scale [104], and pilot plants that were tested for at least 500 h are listed in Table 12.

Table 12. List of pilot plants for membrane-based CO₂ separation.

Institute and Location	Industrial Process	Membrane Type and Material	Membrane Module	Duration	Size	Purity and Recovery (%)	Ref.
SINTEF and NTNU Norway	Coal-fired power plant	Polyvinylamine	Plate-and-Frame	6.5 months	1.5 m2	75	[105]
Helmholtz-Zentrum Geesthacht, Germany	Coal-fired power plant	Multilayer thin film composite membrane	Plate-and-Frame	740 h	12.5 m2	68.2 and 42.7	[106]
Membrane Technology & Research, USA	Coal-fired power plant	Polaris™	Spiral-wound	1800 h	1 ton per day	90	[107]
Membrane Technology & Research, USA	Coal-fired power plant	Polaris™	Hollow-fiber and Spiral Wound	1000 h	20 ton per day	-	[107]
The Ohio State University	Coal-fired power plant	Facilitated transport membrane (FTM) made of composite material	Spiral-wound	500 h	1.4 m2	94.5 and 40	[108]

Table 12. List of pilot plants for membrane-based CO₂ separation.

Institute and Location	Industrial Process	Membrane Type and Material	Membrane Module	Duration	Size	Purity and Recovery (%)	Ref.
SINTEF and NTNU Norway	Coal-fired power plant	Polyvinylamine	Plate-and-Frame	6.5 months	1.5 m2	75	[105]
Helmholtz-Zentrum Geesthacht, Germany	Coal-fired power plant	Multilayer thin film composite membrane	Plate-and-Frame	740 h	12.5 m2	68.2 and 42.7	[106]
Membrane Technology & Research, USA	Coal-fired power plant	Polaris™	Spiral-wound	1800 h	1 ton per day	90	[107]
Membrane Technology & Research, USA	Coal-fired power plant	Polaris™	Hollow-fiber and Spiral Wound	1000 h	20 ton per day	-	[107]
The Ohio State University	Coal-fired power plant	Facilitated transport membrane (FTM) made of composite material	Spiral-wound	500 h	1.4 m2	94.5 and 40	[108]

4.2.5. State-of-the-Art in Physical Separation

Physical separation methods are currently in the TRL 9–11 range. Industrial-scale physical separation-based CO₂ capture plants are summarized in Table 13. Physical absorptions-based CO₂ capture processes, namely Selexol and Rectisol, are the most advanced of all physical separation methods for CO₂ capture. Indeed, two of the largest commercial CO₂ capture plants employ the Selexol process for natural gas processing: the Fort Stockton, US plant captures 8.4 Mton of CO₂ per year, and the Shute Creek Gas Processing Facility, Wyoming, US captures 7.0 Mton of CO₂ per year. Conversely, only VSA among cyclic adsorption processes has reached commercial maturity. Currently, Air Products in Port Arthur, US is operating the only VSA plant, capturing 1 Mton of CO₂ per year from a steam methane reforming unit.

Table 13. Current industrial-scale CO₂ capture plants worldwide based on physical separation methods [5,17].

Operation Year	Location	Project	Industrial Operation	Separation/Capture Technology	CO2 Capture Capacity (Mt/Year)
2020	Alberta, Canada	ACTL with North West Sturgeon Refinery CO2 stream	Hydrogen production from bitumen gasification	Rectisol process	1.3
2017	Illinois, US	Illinois Industrial Capture and Storage Project	Ethanol production	Dehydration and compression	1.1
2013	Rio de Janeiro, Brazil	Petrobras Santos Basin pre-salt oilfield CCS	Natural gas processing	Membrane process	3.0
2013	Coffeyville, US	Coffeyville Gasification Plant	Hydrogen for fertilizer manufacture	Selexol process	1.0
2013	Lost Cabin, US	Lost Cabin Gas Plant	Natural gas processing	Selexol process	1.0
2013	Port Arthur, US	Air Products Port Arthur	Hydrogen production	Vacuum swing adsorption	1.0
2013	Wyoming, USA	The Lost Cabin Gas Plant	Natural gas processing	Selexol process	1.0
2010	Fort Stockton, US	Century Gas Processing Plant	Natural gas processing	Selexol process	8.4
2008	Midale, Canada	Weyburn-Midale CO2 Project	Synthetic natural gas from Coal gasification	Rectisol	3.0
1986	Wyoming, US	Shute Creek Gas Processing Facility	Natural gas processing	Selexol process	7.0
1984	Beulah, North Dakota	The Great Plains Synfuels Plant (GPSP)	Syngas production from coal	Rectisol process	5.8
1972	Texas, US	Terrel Natural Gas processing plant	Natural gas processing	Selexol process	0.5

Table 13. Current industrial-scale CO₂ capture plants worldwide based on physical separation methods [5,17].

Operation Year	Location	Project	Industrial Operation	Separation/Capture Technology	CO2 Capture Capacity (Mt/Year)
2020	Alberta, Canada	ACTL with North West Sturgeon Refinery CO2 stream	Hydrogen production from bitumen gasification	Rectisol process	1.3
2017	Illinois, US	Illinois Industrial Capture and Storage Project	Ethanol production	Dehydration and compression	1.1
2013	Rio de Janeiro, Brazil	Petrobras Santos Basin pre-salt oilfield CCS	Natural gas processing	Membrane process	3.0
2013	Coffeyville, US	Coffeyville Gasification Plant	Hydrogen for fertilizer manufacture	Selexol process	1.0
2013	Lost Cabin, US	Lost Cabin Gas Plant	Natural gas processing	Selexol process	1.0
2013	Port Arthur, US	Air Products Port Arthur	Hydrogen production	Vacuum swing adsorption	1.0
2013	Wyoming, USA	The Lost Cabin Gas Plant	Natural gas processing	Selexol process	1.0
2010	Fort Stockton, US	Century Gas Processing Plant	Natural gas processing	Selexol process	8.4
2008	Midale, Canada	Weyburn-Midale CO2 Project	Synthetic natural gas from Coal gasification	Rectisol	3.0
1986	Wyoming, US	Shute Creek Gas Processing Facility	Natural gas processing	Selexol process	7.0
1984	Beulah, North Dakota	The Great Plains Synfuels Plant (GPSP)	Syngas production from coal	Rectisol process	5.8
1972	Texas, US	Terrel Natural Gas processing plant	Natural gas processing	Selexol process	0.5

4.3. Future Commercial and Demonstration Scale Carbon Capture Plants

Carbon capture technologies are continuously developing, and their applications are expanding to sectors other than power generation, as the technology is suitable for a broad spectrum of carbon intensive sectors and emission sources. Carbon capture technologies do not consist of a discrete product, but rather are infrastructural projects. Therefore, challenges faced by one part of the development chain will affect the entire carbon capture technology progression. Although different carbon capture technologies are commercially available, there is still potential for improvement with respect to cost, performance, and operational flexibility. The nature of carbon capture technology applications is largely dictated by national and regional circumstances and industrial make-ups. For example, some countries will focus primarily on applications for coal-fired power generation, while others may target applications in carbon intensive industries such as natural gas processing and hydrogen and cement production. Currently, there are around 25 commercial scale carbon capture plants in operation worldwide, capturing around 50 million tons of CO₂ per year across a range of sectors and employing different capture methods. Additional commercial and demonstration scale carbon capture plants around the world are expected to come into operation in the next 3–5 years [109]. In this section, we present future commercial (TRL-9–11) and demonstration (TRL 7–8) plants, categorized according to the separation technology employed.

Table 14. Status of the chemical absorption-based future carbon capture plants [17].

Operational	Location	Project	Industrial Operation	Capture Technology	CO2 Capture Capacity (Mt/year)	Status	Scale
2027	Ijmuiden, The Netherlands	Everest project	Steel, Fischer-Tropsch hydrocarbons	Amine	-	Speculative	Commercial
2025	North Dakota, USA	Project Tundra	Coal gasification, Electricity	Amine solvent	-	In planning	Commercial
2025	Teesside, UK	Clean Gas Project	Power, Gas	Aqueous ammonia/amine/amino acid system	6	In design	Commercial
2025	Sjobol, Sweden	Preem CCS	Oil, Refinery products	Chilled ammonia or amine solvent	1.5	In planning	Demonstration
2024	New Mexico, USA	San Juan Gen. Sta. Carbon Capture Retrofit Project	Coal gasification	MHI amine solvent	6	Speculative	Commercial
2024	St Fergus, UK	Acorn CCS Project, Acorn Hydrogen	Natural gas processing	Amine solvent	0.3	In design	Demonstration
2023	Hengelo, The Netherlands	Twence	Electricity, heat	Aqueous amine/solvent system	0.1	In build	Commercial
2022	Ariyalur, India	Dalmia Cement	Cement	amine-promoted buffer salt—proprietry solvent system	0.5	Speculative	Demonstration
2021	Klemetsrud, Norway	Fortum Oslo Varme	Electricity	Cansolv CO2 amine-based capture technology	0.2	In design	Demonstration
2020	Omuta city, Japan	Mikawa Demonstration Plant	Electricity	Amine solvent	0.18	In build	Demonstration
2019	Fredrikstad, Norway	Frevar capture plant	Electricity	Amine	0.15	Speculative	Demonstration
2017	Daejeon, Republic of Korea	Korea-CCS 1	Electricity	Amine solvent	-	In planning	Demonstration
2017	Dongying, China	Sinopec Shengli Power Plant CCS Project	Electricity	amine (MEA based)	-	In design	Demonstration
2017	Xiaomo, China	Haifeng Power Plant CCS Plan	Electricity	Solvent-based chemical absorption—amine.	-	Speculative	Demonstration
2017	Jinjiezhen, China	Jinjie Power Plant CCS Demonstration Project	Electricity	solvent absorption and solid adsorption	0.15	In planning	Demonstration
2017	Brooks, Canada	Bow City Power Project	Electricity	Amine solvent	1	In planning	Demonstration
2016	Texas, USA	Ramsey Gas Processing Plant	Natural gas	Amine scrubbing		In build	Demonstration
2016	Estevan, Canada	Shand CCS Project	Electricity	Amine solvent	2	speculative	Commercial
2015	Redwater, Canada	Nutrien Redwater Nitrogen Plant	Fertilisers	Solvent-based chemical absorption, inorganic, Benfield process.	-	In build	Commercial
-	Teesside, UK	Lotte Chemicals CCUS Project	polyethylene terephthalate (PET) for plastic bottles	Amine solvent	0.5	In design	Demonstration
-	Nebraska, USA	Gerald Gentleman Capture Project	Coal gasification, Electricity	Advanced solvent	2	In planning	Commercial

and

Table 15. Status of the physical absorption-based future carbon capture plants [17].

Operational	Location	Project	Industrial Operation	Capture Technology	CO2 Capture Capacity (Mt/Year)	Status	Scale
2021	Zibo, China	Sinopec Qilu Petrochemical CCS Project	Syngas for methanol and butyl alcohol	Rectisol	1	In build	Demonstration
2020	Louisiana, USA	Lake Charles Methanol Project	Petcoke, byproduct from oil refining, Methanol	Rectisol	4	In design	Commercial
2019	Mississippi, USA	Mississippi Clean Energy Project	Petcoke, Oil, Methanol and Gasoline	Rectisol	4	Speculative	Commercial
2019	Osaki-Kamizima Island, Japan	Osaki CoolGen Project	Electricity	Physical absoprtion		Operational	Demonstration
2017	Jinjiezhen, China	Jinjie Power Plant CCS Demonstration Project	Electricity	Solvent absorption and solid adsorption	0.15	In planning	Demonstration
2017	Jingbian City, China	Yangchang Jingbian Phase 2	Liquid fuels/chemicals	Rectisol process	0.36	In design	Demonstration
2016	Redwater, Canada	North West Redwater	Liquid fuels and feedstocks	Rectisol	1	In build	Commercial
2014	Nanjing, China	Sinopec Eastern China CCS Project	Ammonia	Rectisol	0.5	speculative	Demonstration
	Colorado, USA	Holcim Portland Cement Plant CCS Project	Coal and limestone gasification, Cement	Structured solid absorbent		Speculative	Commercial

lists carbon capture plants based on chemical absorption, predominantly amine- and aqueous ammonia-based absorption methods and physical adsorption. Two of the largest plants are located in USA and anticipated to be operational in 2024 and 2025, capturing 6 million tons of CO₂ per year each, using amine and aqueous ammonia solvent, respectively. Two carbon capture plants using solid adsorbents are also in the planning phase. The plant located in the USA will use a solid adsorbent at commercial scale, While the Jinjie Power Plant CCS Demonstration Project in China will use a combination of both solvent absorption and adsorption methods for CO₂ capture (

Table 16. Status of the oxyfuel combustion-based future carbon capture plants [17].

Intended Operational Year	Location	Project	Industrial Operation	Capture Technology	CO2 Capture Capacity (Mt/year)	Status	Scale
2020	Colleferro, Italy	Colleferro Oxyfuel	Cement	Oxyfuel	-	In planning	Demonstration
2020	Retznei, Austria	Retznei Oxyfuel Demonstration	Cement	Oxyfuel	-	In planning	Demonstration
2019	Taean, Republic of Korea	Korea-CCS 2	Electricity	Oxyfuel	-	Speculative	Demonstration
2018	Scotland, UK	Caledonia Clean Energy Project	Gas, Electricty and hydrogen	Pre- and post-combustion, and oxyfuel	3	In planning	Demonstration
2014	Taiyuan, China	Shanxi International Energy Oxyfuel Project	Electricity	Oxyfuel	2	speculative	Demonstration

).

A number of oxyfuel combustion demonstration plants are also being planned around the world, particularly for application in cement manufacturing, hydrogen production and electricity production facilities (

Table 17. Status of the future carbon capture plants where the capture technology is unknown [17].

Intended Operational Year	Location	Project	Industrial Operation	CO2 Capture Capacity (Mt/Year)	Status	Scale
2026	Southern North Sea, UK	V Net Zero Humber Cluster	Gas, oil, municipal waste, Steam, electricity, refinery products	8	In design	Demonstration
2025	Dunkirk, France	Dartagnan	chemicals, petrochemicals and steel	3	In planning	Demonstration
2025	North Sea, Denmark	Project Greensand		0.4	In planning	Demonstration
2025	Copenhagen, Denmark	C4—Carbon Capture Cluster Copenhagen	Power, heat	3	In planning	Demonstration
2024	Naturgassparken, Norway	Northern Lights		1.5	In build	Demonstration
2024	Brevik, Norway	Longship (Langskip)	Electricity and heat (EfW), cement		In design	Demonstration
2024	Rotterdam, The Netherlands	PORTHOS CCUS Project	Refinery including hydrogen	2	In design	Demonstration
2023	Rotterdam, The Netherlands	CO2TransPorts	Refinery including hydrogen	10	In design	Demonstration
2023	Schelde, Belgium	Carbon Connect Delta	chemicals, petrochemicals and steel	1	In planning
2021	Texas, USA	White Energy Plainview CO2 Capture Project	Corn and ethanol		Speculative	Commercial
2020	North Dakota, USA	Red Trail Energy CCS Project	Ethanol Production	0.18	Speculative	Demonstration
2020	South Yorkshire, UK	Don Valley	Gas, Electricty		In planning	Demonstration
2019	Duisberg, Germany	H2morrow	Steel	1.9	In planning	Demonstration
2019	Dongguan, China	Dongguan Taiyangzhou IGCC	Electricity		In build	Demonstration
2019	Edmonton, Canada	Lehigh CCS Feasibility Study	Cement	0.6	speculative	Commercial
2018	Rotterdam, The Netherlands	CO2 Smart Grid			Speculative	Demonstration
2018	Antwerp, Belgium	Antwerp@C	transport and storage		In design	Demonstration
2017	North Dakota, USA	South Heart IGCC Project	Coal gasification, Electricity	2	Speculative	Commercial
2017	Yulin, China	Yulin Coal-to-Chemicals Project	Liquid fuel/chemicals	3	speculative	Commercial
2016	Abu Dhabi, UAE	Masdar CCS network	Steel, aluminium, electricity, water		In build	Commercial
2016	North Lincolnshire, UK	Killingholme IGCC Project	Coal gasification, Electricity	2	In planning	Demonstration
2015	Sundance, Canada	TransAlta Sundance Carbon Capture	Electricity		speculative	Commercial
2015	Collie, Australia	Collie South West CO2 Geosequestration Hub	Electricty and industrial products		In planning	Commercial
2012	Redwater, Canada	Alberta Carbon Trunk Line	Petroleum fuels, fertiliser	14.6	In build	Commercial
	Wisconsin, USA	Dane County Landfill Carbon Capture Project	Gas, Electricity		Speculative	Demonstration
	St Fergus, UK	Acorn CO2 SAPLING PCI		5	In planning	Commercial
2027	Humber, UK	Humber Zero	Steam, electricity, refinery products	5	In design	Demonstration
2026	Teesside, UK	Teesside Collective Industrial CCS Project	Electricity, ammonia, hydrogen, PET, other industrial products and services	10	In design	Commercial
2025	Liverpool, Manchester, Chester, Wrexham, UK	HyNet North West	Hydrogen Gas	10	In design	Commercial
2025	Liwa Desert, UAE	ADNOC CO2 Capture Project	Natural gas	4.2	In planning	Commercial
2020	Latrobe Valley, Australia	CarbonNet	Electricity	3	In design	Commercial
2017	Lynemouth, UK	B9 Coal	Coal gasification, Electricity		Speculative	Demonstration
-	Indiana, USA	Wabash Valley Resources	Petcoke, Ammonia	1.75	In planning	Commercial
2026	Scotland, UK	Peterhead Low Carbon CCGT Power Station Project	Gas, Electricty	1.5	In planning	Commercial
2026	Yorkshire, UK	Zero Carbon Humber (ZCH)	Electricity, hydrogen, industrial products	8.25	In design	Commercial
2023	Millmerran, Australia	Integrated Surat Basin CCS Project	Electricity	0.15	In design	Demonstration
2021	Northwich, UK	Tata Chemicals Northwich CCU Project	Sodium bicarbonate	0.4	In planning	Demonstration
2020	Latrobe Valley, Australia	CarbonNet	Electricity	3	In design	Commercial
2018	Scotland, UK	Caledonia Clean Energy Project	Gas, Electricty and hydrogen	3	In planning	Demonstration
2018	Taichung City, Taiwan	Tai-chung CCS	Coal gasification, Electricity	1	In planning	Demonstration
2018	Yijiang, China	Baimashan Cement Plant CCU Demo	Cement	0.05	In build	Demonstration
2015	Dongying, China	Datang Dongying	Electricity		speculative	Demonstration
2013	Delimara, Malta	Delimara	Electricity		In design	Demonstration
2013	Beitang, China	China Guodian Capture and Use Project	Electricity	0.01	In build	Demonstration
2010	Le Havre, France	COCATE Project	transport and storage		Speculative	Demonstration

). Additional carbon capture plants are in the planning, design and/or in-built stage across the world. Their capture technologies are disclosed and are summarized in

Table 18. Leading DAC projects currently operating worldwide [110]. (Note: Power-to-X refers to scope of technologies in production of other forms of energy from electricity such as methane, fuels, ammonia, and hydrogen).

Company	Location	Sector	Start-Up Year	CO2 Capture Capacity (tCO2/Year)
Climeworks	Switzerland	Greenhouse fertilization	2017	900
Climeworks	Switzerland	Beverage carbonation	2018	600
Climeworks	Germany	Power-to-X	2019	3
Climeworks	The Netherlands	Power-to-X	2019	3
Climeworks	Germany	Power-to-X	2019	3
Climeworks	Switzerland	Power-to-X	2018	3
Climeworks	Germany	Customer R&D	2015	1
Climeworks	Switzerland	Power-to-X	2016	50
Climeworks	Italy	Power-to-X	2018	150
Climeworks	Germany	Power-to-X	2020	50
Climeworks	Iceland	Mineralisation of CO2	2017	50
Carbon Engineering	Canada	Power-to-X	2015	365

. The largest of these, the “Alberta Carbon Trunk Line (ACTL)” project, is in-built in Redwater, with a sequestration capacity of 14.6 Mt of CO₂ per year from Nutrien, a fertilizer producer. Another large-scale CO₂ capture facility is in design located in Rotterdam, The Netherlands under the design-stage “CO₂TransPorts” project in Rotterdam, NL, is anticipated to be operational in 2023, capturing 10 million tons of CO₂ per year from a hydrogen production facility. Two large-scale carbon capture plants are in design in the United Kingdom, each with capacity of about 10 million tons per year. The Teesside-based “Teesside Collective Industrial CCS Project” will be operational in 2026 and utilize both post-combustion and pre-combustion methods to capture CO₂ from a hydrogen production unit. The Liverpool-based “HyNet North West” project will be operational in 2025 and utilize pre-combustion CO₂ capture technology also in a hydrogen production unit [17].

5. Direct Air Capture (DAC)

Jurisdictions across the world are actively exploring pathways for reducing carbon concentration in the atmosphere [111]. Reduction of atmospheric carbon can be achieved by direct air capture (DAC) processes, or biological processes via photosynthesis. The following section will shed some light on these technologies and current state-of-the-art.

Direct air capture (DAC) is a technology that removes CO₂ directly from the atmosphere [112]. The air-captured CO₂ can either be recycled and utilized as a raw material, or permanently removed through safe underground injection and storage. At present, CO₂ air capture technologies utilize liquid sorbents, [113] solid sorbents [112] or amine-based chemical sorbents [114]. The use of reversible sorbents that can be recycled many times to capture and release of atmospheric CO₂ is an area of significant ongoing research. Figure 11 shows the CO₂ capture process from air, where the absorption and adsorption steps are illustrated, including the release of captured CO₂ upon heating the sorbent materials.

Given its decoupling from specific point sources, a major strength of DAC technology is the much higher flexibility in choosing a location for the plant. Conversely, the main disadvantage of DAC technology is the low concentration of CO₂ in ambient air compared that from point sources such as power or manufacturing plants, which makes this technology expensive and highly energy-intensive compared with other options for carbon mitigation [115].

In direct air capture technology, the choice between solid sorbents and liquid sorbents depends on the packing materials that maximize surface area and, in turn, the interactions between CO₂ and the chemical base. Liquid solvents can coat the packing material in a thinner layer, which leads to lower liquid-phase diffusion resistance at the gas–liquid interface [116]. Aqueous sodium hydroxide (NaOH), calcium hydroxide (Ca(OH)₂) and potassium hydroxide (KOH) are benchmark examples of liquid solvents used in DAC. For instance, when using aqueous KOH, CO₂ reacts with KOH at the gas–liquid interface to produce potassium carbonate (K₂CO₃), where the K₂CO₃ stoichiometry indicates that two KOH molecules are needed for sequestration of one CO₂ molecule [116]. Due to the very low concentration of CO₂ in air, a strong base is required for adequate separation which also constitutes for higher energy requirement for this separation process [117].

Currently, a total of fifteen DAC plants are in operation across Canada, Europe, and the United States, as shown in Table 18. Most of these are small-scale pilot and demonstration facilities, with the captured CO₂ diverted to several uses such as beverage carbonation and production of fuels. At present, two commercial-scale Direct Air Capture facilities are operating in Switzerland, with the captured CO₂ being redirected for use in beverage carbonation and to enhance plant growth in greenhouses [9].

Direct air capture processes range from TRL 1–3 (mitigation potential of ca. 4 Gt-CO₂/year) [118] to TRL 4–6 with potential capacity of up to 10 Gt-CO₂/year [119]. Carbon Engineering (CE) was the first commercial organization to develop and implement solvent-based Direct Air Capture (DAC) technology. In CE’s system, potassium hydroxide serves as the primary solvent, while a calcium caustic recovery loop is used to regenerate the solvent and capture CO₂ efficiently. From developing a first pilot-scale DAC plant in British Columbia, Canada in 2015, their subsequent efforts (2019–2021) focused on developing design and construction of a DAC demonstration plant. Currently CE is finalizing engineering designs for a DAC plant in the Permian Basin in partnership with Oxy Low Carbon Ventures, [120] with a target capacity of up to 1 million tonnes of CO₂ per year [121]. They have placed their system at a TRL of 7 [122]. The Swiss company Climeworks launched the first commercial DAC plant in 2013, with a goal of capturing 225 million tonnes of CO₂ by 2025 [116]. They require approximately 450 TWh of energy with an energy consumption of 2000 kWh per tCO₂ [123]. Currently, Climeworks ranks its own low temperature DAC technology at TRL 9 [124].

As a leading figure in the DAC industry, Global Thermostat has established two pilot facilities, each designed to capture between 3000 and 4000 tonnes of carbon dioxide annually. They have entered into a collaboration with ExxonMobil to advance their technology towards a 1 million tonnes of CO₂ per annum capture target [116]. DAC companies such as Climeworks, Carbon Engineering and Global Thermostat recognize several issues still affect the technology, from the overall high costs of the process to the lack of appropriate policy frameworks, and insufficient stakeholder awareness and education on the potential of DAC technologies [122,125]. Improvements in sorbents loading efficiencies and packing of material, and curbing overall process development costs (e.g., in equivalent volume, solid sorbents have a notably higher contact area compared to liquid-sorbent packing materials) are some of the areas for future research required to advance the state-of-the-art of the DAC technology [116]. In addition to DAC, other methods have also been reported in the literature for potential CO₂ removal from atmosphere (

Table 19. An overview of methods employed for Global CO₂ removal potentials from atmosphere alongside technology readiness levels.

Method	Global CO2 Removal Potential (GtCO2 pa)	TRL	References
Afforestation/reforestation	3–20	8–9	[126,127]
Forest management	1–2	8–9	[127,128]
Biochar	2–5	3–6	[126,129]
Bioenergy with carbon capture and storage (BECCS)	10	7–9	[128,130]
Ocean fertilisation	1–3	1–5	[131,132]
Building with biomass	0.5–1	8–9	[119]
Enhanced weathering	0.5–4	1–5	[128,133]
Ocean alkalinity	40	2–4	[134,135]
Direct air capture	0.5–5	8–9	[9,136]

).

6. Bioenergy with Carbon Capture and Storage (BECCS)

Bioenergy with carbon capture and storage (BECCS) is considered promising due to its dual benefits of reducing emissions while enabling the production of value-added fuels and chemicals. It encompasses any energy pathway in which CO₂ is captured from biogenic sources and permanently sequestered. A schematic representation of the BECCS process is presented in Figure 12.

BECCS is the only carbon dioxide removal technology that also generates usable energy. This process facilitates negative emission where the atmospheric carbon is absorbed by the plants through photosynthesis method. During the energy conversion process, the carbon is captured and stored permanently in different geological location. This process has enormous potential in mitigating climate change when dedicated biomass is used for power generation. Based on CO₂ capture projects in the early and advanced stage of deployment, CO₂ capture through biogenic source could reach around 60 Mt CO₂/year by 2030. This target is far behind the target set by the Net Zero Emission (NZE) scenario by 2030 which is 185 Mt/year. Therefore, it would be necessary to translate the recent momentum into operational capacity for BECCS projects [110,137,138].

Biogenic sources for BECCS include emissions from biofuel and biohydrogen production, heat and power generation in biomass-fired or co-fired power plants, waste-to-energy facilities, industrial applications using biomass, and the use of biochar as a reducing agent in steel production. Currently, approximately 2 million tonnes (Mt) of biogenic CO₂ are captured annually, with less than 1 Mt stored in dedicated geological storage. Notably, around 90% of the captured CO₂ originates from bioethanol production, which is among the most cost-effective BECCS applications due to the high CO₂ concentration in the process gas stream. The Illinois Industrial CCS Project, operational since 2018, is currently the largest BECCS initiative, capturing CO₂ for storage in deep geological formations. Following this, the Red Trail Energy and Blue Flint bioethanol plants—launched in 2022 and 2023 respectively—rank as the second and third largest BECCS facilities in the United States.

While bioethanol remains the leading application of BECCS, a growing number of projects in the power and industrial sectors are expected to be realized. By 2030, approximately 70 additional bioethanol facilities are planned, collectively aiming to add around 20 million tonnes of biogenic CO₂ capture capacity.

Recent project announcements over the past three years indicate that BECCS applications are expanding beyond bioethanol into sectors such as heat and power, hydrogen production, and the cement industry. It is estimated that around 30 million tonnes of biogenic CO₂ could be captured from bio-based heat and power plants, as well as waste-to-energy facilities. For instance, Denmark began constructing two combined heat and power plants in 2023, funded by the Danish Energy Agency under its CCUS subsidy scheme. In the cement sector, seven plants are planning to integrate biomass as a feedstock in clinker production and retrofit CCUS technologies, aiming for carbon neutrality rather than carbon negativity. Notable examples include the Brevik Norcem Plant in Norway, currently under construction, along with advanced projects such as the Go4ECOPlanet project in Poland, the Edmonton cement plant in Canada, the Padeswood plant in the United Kingdom, and the GeZero carbon capture project in Germany [138].

However, beyond niche applications, the limited deployment of BECCS technologies creates uncertainty around their broader commercial viability. As shown in

Table 20. Leading BECCS projects currently operating worldwide [110].

Plant Name	Location	Sector	Start-Up Year	CO2 Capture Capacity (kt/Year)
Stockholm Exergi AB	Sweden	Combined heat and power	2019	Pilot
Arkalon CO2 Compression Facility	USA	Ethanol production	2009	290
OCAP	The Netherlands	Ethanol production	2011	<400
Bonanza BioEnergy CCUS EOR	USA	Ethanol production	2012	100
Husky Energy CO2 Injection	Canada	Ethanol production	2012	90
Calgren Renewable Fuels CO2 recovery plant	USA	Ethanol production	2015	15
Lantmännen Agroetanol	Sweden	Ethanol production	2015	200
AlcoBioFuel bio-refinery CO2 recovery plant	Belgium	Ethanol production	2016	100
Cargill wheat processing CO2 purification plant	UK	Ethanol production	2016	100
Illinois Industrial Carbon Capture and Storage	USA	Ethanol production	2017	1000
Drax BECCS plant	UK	Power generation	2019	Pilot
Mikawa post combustion capture plant	Japan	Power generation	2020	180
Saga City waste incineration plant	Japan	Waste to energy	2016	3

, an estimated ten BECCS facilities around the globe are currently in operation [110].

7. Economics of CO₂ Captures

Likely bound to become a crucial component of any decarbonization strategy, Carbon Capture technology can offer an urgent response to ongoing efforts to tackle climate change around the globe. According to the Intergovernmental Panel on Climate Change (IPCC), implementing carbon capture at a modern conventional power plant can reduce atmospheric emissions by approximately 80–90% compared to a similar plant without CCS technology. As jurisdictions worldwide pursue the transition to a zero-emissions economy, carbon capture technology represents a significant opportunity for mitigating CO₂ emissions at massive scales. Key technical factors affecting CCS technology costs include e.g., plant size, total efficiency, total capacity, plant lifetime, fuel type and its cost. Capital costs also vary depending on whether the technology under-consideration is being applied to a to-be-built power plant or to retrofit existing plants [139,140]. Several studies have analyzed the costs associated with different carbon capture technologies [141,142,143], however, an accurate cost analysis should consider the unit prices in different countries, rise in inflation, taxation rate [144]. In this section we will discuss recent estimates on techno-socio-economic aspects of different CO₂ capture technologies, with a view to identifying key cost drivers of these approaches, rather than providing a comprehensive cost analysis. Note that in this discussion CO₂ capture costs only are considered, while storage, transportation and utilization costs are out of scope of this analysis.

The factors affecting costs of carbon capture approaches are associated with plant size/capacity, types of energy sources, equipment and its deployment and liquid solvent/solid sorbent for separating CO₂. Compared to physical solvents, significant cost savings, including lower capital and operating costs, can be achieved with solid sorbents [145]. Among point source carbon capture technologies, pre-combustion carbon capture offers a viable approach that separates CO₂ and is usually associated with integrated gasification combined cycle (IGCC). Pre-combustion capture costs are highly dependent on the type of absorbent used to separate CO₂. For example, when employing an ionic liquid such as [hmim][Tf₂N] as a physical solvent in an IGCC plant, the primary energy penalty arises from product compression and solvent circulation. Meanwhile, the main contributors to capital costs are the compressors and absorbers [146]. Simulations exploring the impact of plant size on the cost of CO₂ capture processes based on ILs chemical absorbents with 10~100 kmol/h CO₂ treatment capacity (i.e., 3.96 t/h of CO₂ captured) [147] indicate that the energy consumed in terms of electricity, thermal heat and refrigeration varies with different types of solvents used. Similarly, IL based MEA processes to remove CO₂ from raw natural gas are more energy- and cost-efficient compared to conventional MEA [148]. In addition, Ashkanani et al. [149], through numerical study has demonstrated that CO₂ capture using physical solvents ((Selexol, PEGPDMS-1, NMP, [aPy][Tf₂N] and [hmim][Tf₂N]) at lower temperature showed lower Levelized costs of CO₂ captured (LCOC) compared to higher temperature. This is due to the increased solubility of CO₂ in the solvents at lower temperature requiring smaller absorber diameter and lower solvents circulation rates. Among the five solvents, the hydrophobic PEGPDMS-1 was the most promising due to its lowest capital and operating cost and due to its non-corrosive properties enabling less expensive materials for the process equipment.

For DAC, the high costs are mostly because of the lower CO₂ concentration in ambient air, as this requires large units to capture the gas, and thus high upfront capital costs [150]. Oxyfuel combustion capture, while attractive as it does not require a costly system such as those of post-combustion capture systems, does need an air separation unit to obtain relatively pure oxygen for combustion.

Table 21. Summary table comparing major carbon capture technologies across key dimensions. [151,152,153,154,155,156].

Technology	Capture Mechanism	Typical CO2 Source	Capture Efficiency	Cost (\$/Ton CO2)	Scalability	Pros	Cons
Amine Scrubbing	Chemical absorption using amine solvents (e.g., MEA)	Power plants, cement, steel	High (up to 95%)	45–65	High	Mature tech, high efficiency, retrofittable	Solvent degradation, high energy use, corrosion
Calcium Looping	CO2 reacts with CaO to form CaCO3, then regenerated by calcination	Cement, lime, power plants	High (85–95%)	30–70	Medium	Uses cheap materials, high purity CO2 stream	High temperature, energy-intensive regeneration
Chemical Looping	Metal oxides transfer oxygen to fuel, separating CO2 without air	Power generation, industrial	High (up to 99%)	40–80	Medium	No direct contact with air, inherent CO2 separation	Complex reactor design, limited commercial deployment
Membrane Separation	Selective membranes allow CO2 to pass through based on size or solubility	Natural gas, biogas, flue gas	Moderate (50–90%)	50–80	High (modular)	Compact, no chemicals, low maintenance	Lower selectivity at low CO2 concentrations
Direct Air Capture (DAC)	Chemical or physical capture of CO2 from ambient air	Ambient air	Low–Moderate (30–70%)	250–600	Growing (modular)	Negative emissions, location-flexible	High energy demand, expensive
BECCS	Biomass combustion with CO2 capture and storage	Biomass power plants	High (70–90%)	60–160	Limited by biomass	Negative emissions, renewable-based	Land use, food vs. fuel, biodiversity concerns
Physical Absorption	CO2 dissolves in solvents under high pressure (e.g., Selexol, Rectisol)	Natural gas, syngas	High (up to 95%)	30–60	Medium	Effective at high pressures, no chemical reaction	Requires compression, solvent losses
Adsorption	CO2 adheres to solid surfaces (e.g., zeolites, MOFs)	Flue gas, biogas	Moderate–High (60–90%)	40–100	Medium	Regenerable, low energy, tunable materials	Sensitive to moisture, lower capacity than liquids

summarizes energy and cost assessments for the different capture approaches across key dimensions. The cost assessments vary by scale, location and energy source. The scalability refers to current commercial readiness and infrastructure compatibility. The capture efficiency is governed by the CO₂ concentration and process integration.

8. Opportunities and Challenges in the Commercialization of Carbon Capture Technologies

All carbon capture technologies discussed in this paper have their own advantages and disadvantages, and for each specific challenges still need to be overcome towards their broader uptake and implementation. These range from e.g., minimizing impurity-related disruptions in system operation, to scaling up to power plant-level application, and/or retrofitting existing plants/facilities. For example, in chemical absorption-desorption processes, an ongoing challenge is the energy intensity of the MEA solution regeneration step [157]. Capturing 1 ton of CO₂ through MEA-based technology could still emit about 352 kgs of CO₂ if coal is used as the energy source [158]. In addition, in a conventional coal-fired power generation facility where SO₂ coexists with CO₂, there is a possibility of reaction between SO₂ and the MEA solution [159]. The MEA solution can also react with the oxygen present in the flue gases, which could cause corrosion of the equipment. Hence, the concentration of the MEA solution must be carefully monitored. When using solid absorbents for industrial scale CO₂ capture, the flue gas must be pre-treated prior to the adsorption phase, to remove moisture and other contaminants such as SO_x and NO_x that could contaminate the adsorbents and affect their structural integrity and life span [160].

Based on the above techno-economic considerations and limitations in each case, pre-combustion CO₂ capture using physical solvents such as methanol appears most suitable for IGCC plants, while oxy-combustion is better aligned with pulverized coal (PC) plants, and post-combustion capture using amines is best suited for NGCC plants [161,162]. The primary challenges associated with post-combustion CO₂ capture in newly constructed coal-fired power plants are the high capital investment and significant energy penalties, but post-combustion retrofits could roughly halve such costs, depending on the site location. As well, the energy required for heating the solvents and compressing the CO₂ can negatively impact and reduce a plant performance by up to 30%, as the plant cooling requirements would increase [163].

Oxy-fuel combustion capture processes are considered relatively mature, especially because various approaches for oxygen separation and flue gas recycling have already been demonstrated and applied in other industries. Oxyfuel combustion capture seems also well suited to waste incineration facilities, which offers advantages such as reduced flue gas volume, elevated combustion temperatures, and the potential for retrofitting existing incineration facilities. However, further research is needed to adapt this technology effectively to incineration applications [164].

9. Conclusions and Future Research Direction

Carbon capture technologies can serve as a key driver in decarbonizing the power sector and other CO₂ intensive industries, especially for industrial sectors where there is no obvious alternative to carbon capture technologies, namely in iron and steel production, natural gas processing, oil refining, and cement production. Indeed, decarbonization of cement plants by oxyfuel combustion and calcium looping have been recognized as a priority for future research. The main key for cost reduction in industrial decarbonization is to use the waste heat from other facility as energy source.

New materials are also continuously being investigated at the lab or bench as promising technologies for CO₂ capture, but their development to the pilot scale is not yet satisfactory. For example, solvent blends alternative to standard MEA solvent, blends incorporating piperazine (PZ) and 2-amino-2-methyl-1-propanol (AMP) have shown promising higher efficiencies compared to MEA at the lab scale, but more research vis-a-vis real industrial conditions is needed to advance scale up of the process.

Ionic liquids (ILs) have shown promise as a next generation CO₂ capture solvents due to their high stability, low volatility, and reasonable adsorption capacity. However, the commercial viability of ionic liquids (ILs) for CO₂ capture is hindered by their poor gas uptake kinetics, primarily due to their high viscosity and molar mass. To overcome these limitations, future research should prioritize the development of functionalized ILs with reduced viscosity and lower molecular weight to enhance mass transfer rates. Among all physical separation technologies, the most advanced and widely used techniques utilize physical absorption methods, with Rectisol and Selexol in particular having reached TRL 9–11. A number of plants worldwide employ these technologies for large scale CO₂ capture. Cyclic adsorption such as VSA and membrane separation processes are also commercialized. A variety of adsorbents have been developed for carbon capture, with activated carbon, zeolites, and metal-organic frameworks (MOFs) showing the greatest potential. However, MOFs are not yet produced at industrial scale, which limits their practical deployment. Advancing the large-scale synthesis of MOFs tailored for real-world applications is therefore essential to enabling their commercial use in carbon capture technologies.

Alongside point source capture technologies, it is crucial to develop in parallel methods for carbon capture from air. DAC, BECC and other Negative Emission Technologies (NETs) are also projected to have a significant impact in reducing CO₂ concentration. Beyond capturing CO₂ from the atmosphere, NETs also enable the compensation of emissions from challenging sectors such as aviation and maritime transport. BECCs technologies are currently commercially deployed with thirteen plants operating worldwide. The techno-economical maturity of BECCs is comparable to that of conventional carbon capture plants from fossil fuel-based process. As discussed, DAC technology is technically and commercially challenging mainly due to the extremely low atmospheric CO₂ concentration, which causes DAC costs to be as much as two orders of magnitude greater than those of point-source capture technologies.

In addition, emerging carbon capture technologies are pushing the boundaries of innovation to make carbon removal more efficient, scalable and sustainable. These include low-energy direct air capture systems that also produces green hydrogen simultaneously, modular CO₂ -absorbing panels for urban use, and carbon-negative concrete that binds CO₂ into building material. Other innovations include ocean-based sequestration using algae, cyanobacteria, and enhanced weathering strategy that mineralize CO₂ in soil. Moreover, hybrid carbon capture systems combining capture with hydrogen production or retrofitting existing infrastructure like cooling towers are attracting high interest. These emerging technologies represent a shift toward multifunctional, decentralized and climate-integrated solutions. As these technologies mature, they could play crucial role in achieving net-zero emissions and counteracting hard-to-abate carbon sources [165,166].

Lastly, providing accurate and detailed multi-level techno-economic analysis to illustrate the financial prospects of a circular economy could accelerate innovation in carbon capture approaches and technology development. Performance against the state-of-the-art can be assessed by standardizing such techno-economic models, which requires clear definition of boundary conditions including cost limitations, return on investment, resource cost curves etc. These boundaries vary based on the carbon capture technology being considered. For technology comparisons, the economic impact of policies and regulations (e.g., permitting costs, tax rates etc.) should be held constant and models should be able to predict the future policy and market conditions considering predicted and desired lifetime of a facility.