Current status of CO2 chemical absorption research applied to CCS: Towards full deployment at industrial scale

Depósito de Investigación de la Universidad de Sevilla https://idus.us.es/ This is an Accepted Manuscript of an article published by Elsevier Applied Energy Vol. 260, on February 2020, available at: https://doi.org/10.1016/j.apenergy.2019.114313 Copyright 2020. Elsevier. En idUS Licencia Creative Commons CC BY-NC-ND Current status of CO2 chemical absorption research applied to CCS: Towards full deployment at industrial scale F. Vegaa*, F. M. Baena-Morenoa, L. M. Gallegoa, E. Portilloa, B. Navarretea, Z. Zhangb* a Chemical and Environmental Engineering Department, Technical School of Engineering, University of Seville, C/ Camino de los Descubrimientos s/n, Sevilla 41092, Spain b William G. Lowrie Department of Chemical and Biomolecular Engineering, The Ohio State University, Columbus, OH 43210, USA *Corresponding authors. E-mail addresses: [email protected]s (F. Vega); zhang.[email protected] (Z. Zhang) Abstract This work provides a wide overview of the state-of-art of the CO2 chemical absorption applied to Carbon Capture and Storage (CCS) technology. The objective is not only to provide the current status of the technology and the research and development activities carried out towards its deployment in the CCS field, but also to identify the future directions and knowledge gaps. A summary of the conventional solvents used for acid gas removal and novel solvent formulations specifically adapted to new challenges such as fossil-fuels power plants and industrial processes was reported. Novel configurations from the conventional CO2 absorption-desorption layout were summarized and their impact on the operational performance and the reboiler duty was further evaluated. Novel opportunities offered by CO2 concentrated flue gas derived from partial oxycombustion were further discussed in the final section. A large review of the published data from pilot plants has been done to facilitate the final comparison between the current status of postcombustion and novel partial oxy-combustion configurations. Demonstration plants currently available and the commercial solutions proposed by the most important companies were briefly described. CCS pilot plant via chemical absorption have been executed in last decades reaching several CO2 capture capacities up to 80 t CO2/day. Commercial scale plants have been recently developed, being US and China the countries which lead the investment funds. The most important commercial scale demo plants, namely Boundary Dam and Petra Nova, were also described. Nevertheless, there were still many countries which need to bet for CCS at large scale. Keywords: Absorption; Carbon Capture and Storage; CO2 capture; Post-combustion; Partial oxy-combustion 1. Introduction Climate change mitigation actions supported by the Conference of Parties (COP-21) is focused on holding a global temperature rise below 2˚C and even further 1.5˚C above pre-industrial levels by 2100. In this sense, the European Union (EU) has proposed the EU 2030 framework for climate change in which different mechanisms and policies to address climate change challenges are identified, laying down the groundwork of the European path towards decarbonisation by 2030 and beyond. The commitment consisted of four key pillars: reduction by 40% of anthropogenic greenhouse gas (GHG) emissions, 32% increase of the share of renewables in the energy supply network, 32.5% of improvements on energy efficiency, a 15% interconnection level of the internal energy market [1]. According to the IEA, global energy demand will grow by 25% by 2040, supported by an equal share of energy supply for oil, gas, coal and low-carbon sources [2]. Energy policies proposed by the EU council and economic growth in Europe will provide a 75% share of fossil fuels in primary energy demand during this period. The reduction in fossil-fuel dependence would not be enough to mitigate energy-related GHG emissions, showing a growth of 20% by this time. This outlook would produce a long-term global average temperature increase of 3.6°C, which is inconsistent with the IPPC 2°C-below target [2]. Therefore, the EU adopted the Strategic Energy Technology (SET) for smart, sustainable and adequate growth, in which the energy and climate challenges have been included [3]. This new energy policy aimed to address the transition to low carbon energy system based on several key challenges: energy efficiency, sustainable transport, security of supply, a smart and sustainable energy system [4]. R&ID activities should strengthen the large-scale renewable deployment and the strengthening of security as regards nuclear energy were pointed out to achieve the goal of two-thirds of electricity from low-carbon sources [5]. The SET Plan considers that carbon capture and storage (CCS) and utilization (CCU) technologies plays a key role in in the portfolio of CO2 emission mitigation alternatives, but efforts must be made to address the barriers hindering its commercial scale development: energyintensive technology, reduction of overall efficiency in power plants or industrial processes, high operation and investment costs, lack of CO2 transport infrastructure in Europe, long-term CO2 storage safety, public acceptance, regulatory framework and CO2 pricing [6]. Within CCS alternatives, post-combustion capture using amine-based chemical absorption is a mature technology which can be ready to retrofit existing power plants in short-term [7]. For this reason, the CCS roadmap proposed by the SET Plan expects that the first commercial coal-fired power plant combined with CCS will be available in the period 2020-2025 and will be widely used in the rest of carbon-intensive industrial processes after that [8]. The key milestone for CCS deployment is set at a total CCS cost reduction of 30%-40% by 2020. It assumes that CCS will contribute up to 30% of the total GHG emission reduction by 2050 and the installed capacity of this technology will grow from 3 GW in 2020 to 3–8 GW in 2030, 22–129 GW in 2040 and 50– 250 GW in 2050 based on a carbon pricing environment during this period. The European Industry Initiatives on CCS have identified the most relevant challenges that must be addressed to achieve the full deployment of this technology on a commercial scale. These challenges are divided in technological issues (for instance evaluation fully integrated CCS on a large-scale or performance and process configuration optimization from learning-by-doing strategies) and future development (CO2 capture cost reduction below 60-90 €/t CO2 and further research on CO2 transport and storage alternatives) [9,10]. There are numerous review papers about CCS in the literature. In particular, several works reported the mechanisms of different solvents applied in CO2 chemical absorption such as ionic liquid, alkanolamines and their blends [11]. Furthermore, other works identified the main constrains hindering the deployment of post-combustion capture based on chemical absorption. In this sense, an assessment of the main barriers for post-combustion CO2 capture processes was also proposed, with the evaluation of several process intensification technologies [12]. Modeling of CO2 capture via chemical absorption processes is one of the most relevant topic and its more recent advances have been also recently reviewed [13]. Moreover, a review of patents of CO2 capture technology development have been analyzed in recent published works [14,15]. Finally, some of the pilot scale CCS projects were studied by Yan and Zhang [16]. Nevertheless, this work is focused on the current initiatives and main insights on CO2 post-combustion capture based on chemical absorption leading for its full deployment at large scale. This work covers the most important knowledge gaps in regards of CO2 capture by chemical absorption which has not been summarized in other review papers, listed as follows: the commercial development of different configurations for CO2 capture in fossil-fuel power plants, as well as the current initiatives towards large-scale deployment of this technology; and also the identification of the cutting-edge of novel applications for CO2 chemical absorption such as partial oxy-combustion. Therefore, a needing for closing the gap of knowledge will come up in a near future. This work arises to serve as a guide for those involved in formulating new strategies – developing the existing technologies for CO2 capture by means of chemical absorption. Herein a critical description of the state-of-art regarding currently post-combustion CO2 capture processes is addressed, both those that are commercially available and those presently being researched. A summary of the post-combustion CCS demonstration projects worldwide is also provided. Based on this overview of the current state of the technology available, the current status of the CO2 chemical absorption for CCS applications is analyzed in terms of the main characterization properties of traditional and novel both solvents and blends, as well as on optimized and integrated configurations from the traditional CO2 chemical absorption layout, which are susceptible to being applied in this CCS technology. This work concludes with a description of the cutting-edge advances of the technology such as partial oxy-combustion capture processes, allowing for an evaluation of the areas that research should focus in this field. To fulfill the points announced, this work embraces references from different timespan. The basis of CO2 capture by means of chemical absorption was first established from the nineties to the beginning of the present century by outstanding authors from that date. Therefore, the more basically aspects of our work were covered directly with literature from this period. In addition, the latest technological developments reported in this work intend to update the most forefront advances in CO2 capture with chemical absorption systems. Accordingly, a wide range of different novel references have been studied with a lifespan covered from 2012 to date. 2. CO2 solvents The fact that real solvents exhibits a combination of desirable and undesirable properties presents new challenges in terms of research into solvents, which should aim to achieve further improvements in CCS based on chemical absorption. A summary of the most relevant solvent tested for CCS applications is described below. Most of the studies dedicated to solvent performance improvements are based on two main approaches as given in sections 2.2 and 2.3. 2.1 First generation The first solvents tested in CCS came from the traditional gas treating process. The amines that have been proven to selectively absorb CO2 from a gas stream on a large scale belong to the alkanolamine family [17,18]. Triethanolamine (TEA), a tertiary amine, was the first commercial solvent that was used in the early purification gas units, followed by monoethanolamine (MEA) and diethanolamine (DEA), a primary and a secondary amine, respectively. methyldiethanolamine (MDEA) (tertiary), diglycolamine (DGA) (primary) and diisopropanolamine (DIPA) (secondary) were also proven to be applied in CO2 separation processes [19]. In general, the CO2-amine reactivity of the above-mentioned solvents shows a linear behavior in terms of the kinetics and the energy requirement for solvent regeneration, mainly depending on the chemical structure of the amine [13]. Primary and secondary amines commonly react with CO2 to form the carbamate ion [20]. However, tertiary amines hydrolyze CO2 based on acidbase considerations [21,22]. The carbamate formation produces stronger CO2-amine bonds than those from hydrolysis mechanisms, which results in higher energy requirements for CO2 release and thus for solvent regeneration [12,23]. Most primary amines have an enthalpy of CO2 solubility about 80- 90 kJ/mol CO2, being slightly lower for secondary amines (70-75 kJ/mol CO2). However, tertiary amines can absorb CO2 with a significant reduction of the enthalpy of CO2 solubility, which is usually found over in the range 40-55 kJ/mol CO2 [24]. Primary and secondary amines provide higher CO2 absorption rates than tertiary amines due to the carbamate formation. These facts make the selection of a proper solvent come down to a trade-off between high performance during CO2 absorption and the cost of the solvent regeneration: solvents that react with CO2 via carbamate formation show faster kinetics that can lead to lower equipment size but require more energy for regeneration [25]. Opposite effects are observed from solvents that absorb CO2 via hydrolysis [26]. 2.2 Second generation - Functionalized solvents Functionalized solvents are formed by the addition of chemical groups to the traditional solvent to alter its molecular structure and geometry. This fact modifies the position and size of the active areas and alters the length and the strength of the bonds formed from the reactive species. Sartori and coworkers [27,28] were the first who proposed this different class of solvents. These solvents, namely sterically hindered amines, form weaker CO2-amine bonds than primary and secondary amines and thus decrease the energy associated with CO2 release without a significant reduction of the CO2 absorption rate. 2-amino-2-methyl-1-propanol (AMP), 1-8-p-menthanediamine (MDA) (primary) and 2-piperidine ethanol (PE) (secondary) are examples of sterically hindered amines typically used for CO2 separation process [28,29]. 2.3 Amine blends This approach combines different amines in order to hybridize their overall performance. The combination of a lower performing solvent such as tertiary amines with higher performing solvents such as primary amines can result in a mixture showing overall absorption improvements compared to those from the individual solvent separately. This practice is commonly referred to as promoting a solvent. MDEA was the first amine combined with faster kinetics amines to enhance its CO2 absorption rate [30]. MEA, piperazine (PZ) and DEA have typically been applied to promote the MDEA solvent performance. Since MDEA blends were first employed in gas purification processes, a high number of mixed solvents have been proposed. Other works proposed the use of high absorption rates solvents to enhance the reaction kinetic of fast solvents [31]. In particular, MEA showed half of the absorption rates than those provided by PZ due to its molecule structure which contains two amino groups. For this reason, PZ has been used as a promoter of MEA aqueous solutions. The MEA/PZ blend resulted in a substantially enhancement of the kinetic of the CO2 absorption reaction only adding a 5wt% of PZ [26,32]. The appearance of the CCS concept strengthened the interest in solvent development and research at the end of the 90s, with the possibility of extending mature CO2 chemical absorption technology to a new area: carbon capture from stationary sources, i.e. fossil-fuel power plants. Further studies have been carried out to determine specifically novel solvents and blends that strengthened their performance under applications for CO2 capture in fossil-fuel power plants via CO2 chemical absorption [33,34]. In this sense, the most desirable solvent properties that can be suitable for CCS applications include: high CO2 loading, fast kinetics, thermal and oxidative stability, along with decrease in energy requirement for regeneration, volatility, viscosity, corrosivity, toxicity, chemical reactivity with impurities and cost [35,36]. In this respect, the CO2 separation process based on mixedsalt solvent emerges as innovative option instead of conventional amine-based solvents. This novel approach is based on the use of ammonia blended with potassium carbonate [37]. Both the ammonia and the potassium carbonate showed several advantages compared to conventional amine-based solvents. They have low environmental impact based on their low toxicity. They do not degrade under high temperature neither the presence of impurities such sulphur compounds, nitrogen oxides and oxygen. They also showed high CO2 loading cyclic capacity and absorption kinetics close to primary amines. It should be noted that they can be stripped at higher temperatures than conventional aminebased solvents and hence they are able to reduce the energy requirements for both the stripping of CO2 and the CO2 compression. However, the huge cooling requirements for the flue gas and the washing stage of the cleaned CO2-free exhaust gas constrain currently its deployment at large scale [37]. The presence of potassium carbonate in aqueous ammonia had benefits on the overall performance of the solvent blend. The addition of K2CO3 reduced the ammonia slip carried in the cleaned exhaust gas. In addition, the heat of CO2 desorption and the mass transfer coefficient were lower under more K2CO3 in the solution. Experiments performed by Lillia [38], demonstrated a diminishing of the heat of desorption at 120 ˚C, from 70 kJ/kmol CO2 to 55 kJ/kmol CO2, as the K2CO3 concentration varied from 1 m to 2 m in 4 m of total concentration of solvent in aqueous solution. At the same conditions, the mass transfer coefficient experienced a 21% of reduction. Results from modelling reported a 44% of reduction of the reboiler duty as mixed-salt were used instead of Econoamine Fluor FG+, reaching a specific energy consumption up to 2 MJ per kg of CO2 for removing 90% CO2 from a 550-MW supercritical power plant [39]. Furthermore, efforts have been made to address the main operational issues related to amine-based solvents. The use of corrosion inhibitors decreases the rate of corrosion and allows to use less expensive stainless steel in the pipework and the process equipment. It should be noted that higher concentrated aqueous solvent (up to 40 wt% in some cases, i.e. MEA [19,40]) has been used in chemical absorption since corrosion inhibitors started over to be employed. Higher concentrated solvents allow for lower equipment size and smaller amounts of water are required for the solvent preparation. Energy consumption can also be reduced by decreased pumping requirements. Other additives such as buffers, anti-foam additives and oxidative degradation inhibitors have been used to avoid common operation issues associated with amine-based solvents and to improve solvent performance in terms of lower degradation products disposal and solvent make-up [41]. An elevate number of blends and solvents has been identified for CO2 capture based on chemical absorption and many studies can be found in the literature. Table 1 reported a list of the most promising studied in recent years. Rochelle´s group from the University of Texas have investigated more than 50 different solvents that can be suitable for use as CO2 solvents for post-combustion capture technology. K2CO3 blended with PZ showed a high performance as a solvent blend from this research group [42,43]. In this sense, others research groups has employed potassium carbonate has been also tested as potential CO2 capture solvent [44,45]. PZ has also been blended with other solvents such as AMP [46,47]. This blend has shown a relevant performance in comparison with conventional MEA 30wt%, reducing the energy consumption of the solvent regeneration up to 10% of the baseline case. The reboiler duty was set at 3.15 GJ/t CO2 and the AMP/PZ blend shows its best performance elevated flue gas flow rate due to the presence of PZ (Fig. 1) [48]. 3. Novel configurations and process integration into fossil-fuels power plants Numerous measures were tested in order to lead for further improvements of the CO2 chemical absorption units since the first installations were erected for acid gas processing. Absorption and desorption processes are strongly coupled. Therefore, the simultaneous optimization of the whole process is crucial to achieve a substantial reduction of the total CO2 capture cost. One of the most promising approaches that can increase the plant efficiency is the heat integration between the power plant and the CO2 capture unit [26,82]. Many modifications from this basic scheme for gas processing operations have been proposed to reduce the energy requirements for solvent regeneration or equipment costs. For example, turbines have been utilized in high and moderate pressure absorption units for energy recovery. In the absorption section, the use of several lean solvent feed inlets were proposed to reduce the absorber size and hence the investment costs reactors [19]. Kohl and Nielsen [19] proposed to primarily add lean solvents in the central section of the absorber where the bulk of CO2 was absorbed. A minor portion of the lean amine was fed at the top of the column to absorb the remaining CO2 in the flue gas and therefore a reduced absorber diameter were required reactors. A concurrent absorption unit before the absorber was also proposed. The rich amine was pumped through the concurrent absorber before being sent to the regeneration process. In this unit, the high CO2 concentrated flue gas was kept in contact with the rich amine to enhance the CO2 loading of the rich amine by means of a switch of the CO2-solvent equilibrium. Therefore, the increase of the solvent capacity leads to lower solvent flow and lower energy requirements in the desorption process [19]. Another modification was proposed which has an impact on the absorber performance. It consists of the installation of intercoolers between the absorber packed beds to reduce the temperature inside the absorber. This approach withdraws a portion of the energy released during the CO2 absorption due to the exothermal reaction, avoiding excessive temperatures in the absorber that can negatively affect the absorption of CO2. The optimum location of the solvent extractions along the absorption column was reported by Thompson and King [19]. They located the point near the bottom of the column where half the absorption occurs above and the other half below this location reactors. Solvent intercooler has been widely used in novel pilot plants applied to postcombustion capture studies [83]. In addition, a water wash is often added to the demister at the top of the absorber to reduce the solvent losses due to both amine volatilization and cleaned gas droplet carrier. The split-flow scheme is illustrated in Fig. 5. In this option, the rich amine from the absorber sump is split into two streams, which are introduced in different sections in the stripping column. The stream fed at the top of the column is partially stripped along its way down and then is extracted at the middle section of the stripper. The semi-lean amine is pumped into the absorber, being introduced near the bottom where the bulk of the absorption occurs. The second split stream is introduced in the down section of the stripper where further CO2 desorption is produced [84]. Then, the lean amine is pumped from the bottom of the stripper to the top of the absorber to yield the absorption of the semi-cleaned gas from the semi-lean absorption section. The use of split flow or inter-stage absorber cooling was demonstrated to get some energy savings. For example, Stec [85] proposed this configuration in a pilot scale unit and obtained a reduction of 5% in reboiler heat duty. Fig. 5. Flow diagram of the split-flow modification. Modified after [19,86]. Several drawbacks have been identified in the literature. The investment cost of the CO2 capture unit is appreciably higher due to the fact that the height of the stripper must be increased somewhat and the process is more complex [87]. Moreover, the split-flow requires two sets of separate piping systems, including double pumps, heat exchanges and coolers [88]. Dubois [88] evaluated the influence of the stripping pressure under this novel configuration using a MDEA/PZ blend. An increase of the stripping pressure lead to a decrease of 25% of the regeneration energy of the optimum L/G ratio as the pressure varied from 200 kPa to 600 kPa (Fig. 6). Fig. 6. Evolution of the specific energy consumption for MDEA/PZ blends under variations of the stripping pressure. Modified after [88]. It should be also noted that measures producing improvements to plant efficiency can lead to further capture cost reductions, but if they introduce new investment and operating costs, the benefits related to efficiency can be offset [84]. Therefore, a trade-off between marginal benefits associated to higher plant efficiency and extra-costs related to novel integration concept implementation should be analyzed prior to making a final decision that affects the design of the CO2 capture unit [26]. Efforts have been focused to develop both novel configurations and ideas 3 4 5 6 6.E-03 7.E-03 5.E-03 4.E-03 3.E-03 2.E-03 Eregen (GJ/t CO 2 ) L/G ratio (l/m 3 ) Pregen = 200 kPa Pregen = 300 kPa Pregen = 450 kPa Pregen = 500 kPa Pregen = 600 kPa for process integration [89–91]. There are also studies focused on the evaluation of the most promising proposals [92,93]. In respect to CO2 absorption, a lot of work related to CO2 absorption improvements is reported from the literature. Cosmos and Gaspar [94] focused on mass-transfer and hydraulic considerations to provide an improved design of the absorber, whereas Fourati [95,96] relies on hydraulic aspects such as liquid spreading and dispersion to enhance the gasliquid contact and so extend the absorption capacity of the solvent. The feasibility of CO2 capture using pulverized columns have also been investigated [97–99]. The integration of a coal-fired power plant with Chilled Ammonia process, using an absorption refrigerator (AR) to provide the chilling load was tested [100]. They obtained that the efficiency penalties can be reduced from 13.23% to 9.82%. More research works have been presented employing ammonia as capturing agent. CO2 capture efficiency achieved was 80-90% with 5-15% NH3 concentration [101,102]. Moreover, removal percentages higher than 95% of SO2 were presented. Two different electrolyte models for CO2 capture by means of ammonia were studied and compared [103]. Extended UNIQUAC model presented better experimental data for larger ranges of temperature and pressure than e-NTRL model. Costs were analyzed both for ammonia and amine based technology, resulting in lower values for the first one (47.03 €/ton CO2 versus 51.62 €/ton CO2). Chilled ammonia process was also studied, which consist on capturing CO2 with ammonia as solvent at low temperatures [104,105]. CO2 capture obtained varied between 75 and 85%, with less energy consumption than previous solvents tested (2.6 GJ/ton CO2) [104,105]. Fig. 7. Schematic diagram of multiple alteration configuration. Modified after [86]. Regarding desorption aspects, many novel stripper approaches have been proposed. Thermomorphic biphasic solvent (TBS) combined with intensification methods is considered a promising alternative for solvent regeneration [82,106]. It is based on the use of a lipophilic amine that can be separated into two phases at low temperature (75°C-80°C). The organic phase formed contains the regenerated lipophilic amine, which can be converted to a single phase by cooling at 40°C-50°C, and the aqueous phase is mainly composed of water and carbamate amine species [107]. According to Zhang [82], extractive regeneration using inert hydrophobic solvents can reduce the desorption temperature down to 40–70 °C and intensifies solvent recovery, releasing more than 90% of CO2 using multiple-stage extraction. This alternative might decrease the reboiler duty up to 50% respect to MEA 30%wt. Note that a new CO2 capture technology based on the TBS process, referred to as the Demixing Solvent process (DMXTM), has been developed by IFP Energies Nouvelles. This technology uses a demixing unit prior to thermal regeneration [108]. After passing through this unit, the lean organic phase is returned to the absorber, while the rich solvent is sent to strip [95]. Zhang [90] proposed a flash evaporation showing a high performance of the stripping section. In recent years, the use of modeling combined with technoeconomic evaluations has been done in order to assess each novel proposal before its further study at experimental scale [109]. Dreillard [108] proposed to use the produced CO2 at 6 bars which turn into subsequent economical savings. According to their study, considering an available steam at 21 €/t, it would be possible to produce CO2 from blast furnace gases at around 40 €/t. Finally, the feasibility of the best alternatives relies on the pilot plant evaluation and later demonstration scale development prior to a fully commercial deployment of the optimum process [26]. More recently, Dubois [88] compared various configurations of the absorption-regeneration processes in cement plant flue gases. They concluded that the heat pump modifications lean vapor compression configuration and Rich vapor compression configuration LVC and RVC lead to 11- 18% energy savings of the CO2 capture process compared to the baseline case using MEA 30%wt. Fig. 7 represents one of the multiple alteration configurations for amine-based absorption. It based on the combination of intercooling in the absorption section, lean amine flash and evaporation of the condensate in the stripper section. Fig. 8. Schematic diagram of a double matrix stripper configuration. Modified after [77]. According to Ahn [77], this novel configuration reduced the reboiler duty up to 2.2 GJ/t CO2 of the energy required for the MEA 30wt% regeneration. Oyenekan and Rochelle studied several configurations of the stripping section and numerous solvents such as KS-1™ and solvent blends using PZ. This study concludes that the combination of MEA-MDEA blend and the double matrix configuration reduced the energy consumption of the overall CO2 capture process up to 22% compared with the conventional configuration using MEA 30wt% as a solvent (Fig. 8) [77]. In addition, PZ combined with the advance flash stripper provided a 10% reduction of the energy required by the reboiler duty, the compression and pumping works [110]. Recently Wang [91] used a novel configuration to direct non-aqueous gas stripping process and exploiting its potential for energy saving through experiments. At ambient pressure for the regeneration stage, they obtained for pentane, hexane and cyclohexane, optimal energy consumptions of 2.38, 2.86, and 3.16 GJ/t CO2, which are 38.8%, 26.5%, and 18.8% lower than that of the conventional process to regenerate solvents from CO2. Regarding the CO2 contained in flue gas from natural gas treatment, CO2 capture by means of chemical absorption is roughly applicable due to the low percentage of CO2 in the flue gas – around 3-5%v/v CO2. For this reason, its application in this kind of power plants is not feasible and this CO2 chemical absorption is still expensive for gas natural, being needed more advances to make it affordable. However, to reduce the impact of the low percentage of CO2 in the flue gas on the CO2 capture costs, the current research in this field aimed at increasing the CO2 concentration in the flue gas in order to enhance the CO2 absorption performance and hence reduce the operational and investment costs. Some of the different strategies to increase CO2 in natural gas flue gas are listed below [111–113]. - Exhaust gas recirculation: CO2 concentration can be increase up to 6%. The main impact is that compressor inlet temperature increases and it need to be cooled to avoid soot formation. - Evaporative gas turbines: it produces an increase in turbine mass flow, which can affect the pressure ratio. Moreover, the CO2 concentration maximum to achieve is 6%v/v CO2. - Supplementary fuel combustion: the overall performance is reduced by several points. CO2 concentration could be increased up to 6%v/v CO2. - Sequential supplementary gas combustion: as in the previous point, the main impact is that the overall performance is clearly reduced. Nevertheless, CO2 concentration can be increased up to 9%. - Selective exhaust gas recirculation in parallel: the maximum CO2 concentration achievable by means of this technology is 18-20%. Nevertheless, this technology need to be further investigated to study the potential problems associated with it implementation. - Selective exhaust gas recirculation in series: as in the previous point, this technology is very promising since it is estimated that a 20% of CO2 composition can be achieved in the flue gas. The compressor working inlet conditions would drastically change in this scenario, but more research is needed to check the impact on the overall performance. Other novel initiatives consist of the use of membranes in combination with solvents for CO2 capture. Membranes have been widely utilized in industry for natural gas treatment [114]. They consist of semi‐permeable barriers that allow selective separation of a gas component from a mixture based on the permeation velocity of each component through the membrane. The membrane can be considered as a filter for one or more gas components and produces a component‐enriched permeate stream. The differential pressure between the feed side and the permeate side is the main driving force to promote component separation from the flue gas. Although membrane technology can be applied in postcombustion applications, it is more suitable for pre‐combustion - CO2 separation from H2 and natural gas - and oxy-combustion - O2 separation from air-. Gas absorption membrane aims to enhance the gas component separation using higher differential pressure as a driving force along the membrane due to the use of a CO2 solvent in the permeate side. In this case, the membrane is combined with a liquid solvent, typically an amine, which can immediately remove CO2 from the flue gas. CO2 is firstly diffused into the membrane and then is chemically absorbed by the use of a solvent in the permeate side. The high CO2 removal rates provide smaller contactor devices using this principle than those from simple gas separation membrane. Moreover, using a membrane prior to CO2 removal by chemical absorption reduces the volume of gas to be treated in the absorber column and consequently decrease the equipment size and the operating cost associated with the overall process [115]. The driving force along the membrane decreases as CO2 is diffused into the membranes. This phenomenon impacts on the flexibility of the process, limiting its application in post‐combustion due to the poor CO2 recovery and purity. Barbieri indicate that the use of membrane in CO2 separation from flue gas containing less than 20% CO2 are inefficient. Membrane also requires a cooling stage to ensure the gas stays at a temperature below 100°C as higher temperatures produce a further degradation of the membrane materials [116]. Despite the low energy requirements (0.5 – 6 MJ/kg CO2), the low CO2 removal capacity and the low purity of the CO2 stream make its implementation difficult on a large scale. Moreover, membranes do not provide a high separation level, so multi‐stage and recycle configuration must be implemented to achieve an affordable degree of CO2 separation. It seems that membrane technology cannot tackle the energy penalties related to CO2 separation in the post‐combustion capture process, but its combination with existing processes, such as absorption membrane separation, may reduce the penalties of the overall CO2 capture process. Some promising alternatives such as facilitated transport membranes, mixed matrix membranes have been also proposed in the literature [117]. 4. CO2 capture testing at pilot plant scale Acquiring data from pilot plant campaigns is crucial to establish a set of design criteria for a further scaling-up of CCS technology toward commercialization. Novel solvents and blends aimed at reducing energy requirements for solvent regeneration are currently testing at pilot plant scale prior to being involved in a demonstration scale evaluation. The aim of these new synthetized solvents is to achieve a variety of desirable properties that can lead to lower energy penalties associated with carbon capture and an optimal process integration. It should be noted that although most of the studies on novel solvent formulation are focused on lowering energy penalties related to solvent regeneration, some tradeoffs exists that must be considered [26,74]. A variety of properties, including corrosiveness, degradation rates, by-products derived from degradation processes, environmental impact, manufacturing cost and operating variables such as cyclic capacity, solvent flow-rate and stripping conditions, should be taken into account to evaluate the overall benefits in a CO2 capture. Table 2 summarized the pilot plants and large experimental installations developed in recent years for the deployment of CO2 capture at industrial scale, mainly focused on developing novel solvents and blends for CO2 chemical absorption applications. The solvents, the main operating condition ranges encountered during the test campaigns and the results available in the literature have been also added. Most relevant studies by institutions such as the University of Texas, CSIRO, KEPRI-MHI, the University of Stuttgart (CASTOR and CESAR projects) and companies such as BASF, DOW, ALSTOM, Fluor Daniel are reported. Results from the latest activities carried out at the Mongstad pilot plant are also included. The experimental installations reported in Table 2 showed a CO2 capacity ranging between 0.1-1 t CO2/day (low capacity level) and 10-80 t CO2/day (high capacity level). licensed by Fluor Co., employs MEA blends as solvent. This technology has achieved reductions of up to 30% of overall energy consumption of the CO2 capture process compared with the conventional MEA-based configurations [50]. Mitsubishi Heavy Industries (MHI) licensed KMCDR™ process which is based on the use of an own sterically hindered solvent, namely KS-1, in combination with an optimized configuration from the conventional process. The application of this technology in a CO2 capture process from pulverized coal power plants reduced by 15% the consumption associated with the conventional configuration of the company, placing the specific consumption of capture in 3 GJ/t CO2 [135]. Finally, Shell Co. provides a novel CO2 capture process namely Shell Cansolv™ CO2 capture system which is a world leading amine-based CO2 capture technology. This technology is suitable to be used in a widely portfolio of industrial process such as energy production, refineries, mining and chemical industries. The most relevant benefits are listed below [136]:  Lower regeneration energy and superior kinetics compared to conventional amines  High loading capacity combined with ease of regeneration  Improved resistance to oxidative and thermal degradation  Advanced solvent and technology development The CCS demonstration projects currently under operation, execution or evaluation worldwide are listed in Table 3. A total of 22 demo projects are primarily focused on power generation and the share of post, pre and oxy-combustion projects is 9, 10 and 3, respectively. Most of the projects use CO2 injections for EOR, whereas other projects provide an opportunity to assess the feasibility of long-term CO2 sequestration in both saline aquifer and dedicated geological formations. The United States and China are the leading countries in CCS development, with 7 and 5 demo CCS projects, respectively. The annual CO2 capacity for storage ranges between 0.8 - 3.8 Mtpa. Don Valley is recognized as the largest CO2 capacity project, with 5 Mtpa. However, the SaskPower Boundary Dam project erected in Canada is the large commercial scale facility for CO2 capture applied to fossil-fuel power plant in the world. It combines a coal-fired power plant with post-combustion capture and CO2 storage. The captured CO2 is used for enhanced oil recovery (EOR) in the oil field named Weybun [136]. From 2014 to the date, the capture facility at Boundary Dam has been operating. It has experimented some difficulties which resulted from a number of design deficiencies and construction, as well as some other issues which needed to be tackled down. These issues were safety, reliability and efficiency and cost-effective operation. Many projects were carried out to solve these problems and the results have been improving in terms of CO2 capture tonnes. From November 2015 to October 2016, this plant achieved to capture 800,000 tonnes of CO2. By March 2018, 2,000,000 tonnes of CO2 were captured in agreement with the latest available data [137]. A recent work studied the differences between Boundary Dam and Petra Nova model by means of a sensitivity analysis of the main parameters (for example coal type, CO2 sale price and plant size). As main conclusion it was obtained that Petra Nova model has several advantages over Boundary Dam for new coal-fired power plants [138]. Petra Nova capture plant was designed to capture 90% of CO2 emissions from a 240 MW coal plant (1.4 million tons of CO2 per year). It is the largest CO2 capture retrofit at a coal plant [139]. Table 3. Status of CCS large-scale projects [16,137–145]. Project Lifecycle stage Country CO2 capacity (Mtpa) Operation date Capture type Storage type Boundary Dam Operation CANADA 1.00 2014 Post EOR Kemper County Done USA 3.00 2016 Pre EOR Petra Nova (NRG Energy Parish CCS Project) Operation USA 1.40 2016 Post EOR Don Valley Establish UNITED KINGDOM 5.00 2019 Pre Geological storage FutureGen 2.0 Failure USA 1.10 2017 Oxy Geological and onshore saline formations HECA Establish USA 2.70 2019 Pre EOR ROAD Operation NETHERLANDS 1.10 2017 Post Geological and offshore depleted reservoir Sinopec Shengli Operation CHINA 1.00 2017 Post EOR Texas Clean Energy Establish USA 2.20 2019 Pre EOR White Rose Establish UNITED KINGDOM 2.00 2020-21 Oxy Geological storage and offshore saline formations Peterhead Establish UNITED KINGDOM 1.00 2019 Post Geological and offshore depleted reservoir Sargas Texas Point Comfort Establish USA 0.80 2017 Post EOR Bow City Establish CANADA 1.00 2019 Post EOR C.GEN Under evaluation UNITED KINGDOM 2.50 2019 Pre - Caledonia Clean Energy Under evaluation UNITED KINGDOM 3.80 2022 Pre Geological and offshore saline formations with EOR Huaneng GreenGen Under evaluation CHINA 2.00 2020 Pre EOR and geological (under review) Korea-CCS 1 Under evaluation KOREA 1.00 2018 Post Geological and offshore Korea-CCS 2 Under evaluation KOREA 1.00 2020 Pre Geological and offshore Quintana South Heart Cancelled USA 2.10 2018 Pre EOR China Resources Power (Haifeng) Establish CHINA 1.00 2020 Post Geological and offshore saline formations Dongguan Taiyangzhou Establish CHINA 1.20 2019 Pre Geological and offshore depleted reservoir SRI´s ammoniabased CO2 capture Establish USA - NORWAY 0.1 2019 Post - Shanxi Under definition CHINA 2.00 2020 Oxy - The complete deployment of CCS technologies will not be achieved without policies that establish a price on CO2 emissions. Indeed, stakeholders have identified a lack of a clear first-movement advantage. Developing CCS at demonstration scale is a costly undertaking. Such efforts must lead to a worthy knowledge that can outweigh the cost associated with its generation [146]. Although CCS development can provide advantages that ensure safe investment facing the future regulatory framework, the uncertainties related to this regulatory framework increase the likelihood that CCS deployment will be compelled [147]. The deployment of CCS technology for climate change mitigation purposes will therefore require policy action. In accordance with Bennet and Heidug, several break points have been defined in order to determine key changes in current policies designed for three difference steps [147].  Step 1. Generation of knowledge for different CCS technologies as a public asset. This knowledge would help to identify high-performance and potential low cost CCS technologies.  Step 2. If CO2 pricing remains below the carbon capture cost, investment in CCS projects must be promoted by means of decreasing the risk exposure of stakeholders that can unlock private investment in CCS projects for continued learning-by-doing.  Step 3. Once the mature CCS technologies achieve complete deployment, public investment must be reduced. It will require actors to address externalised CO2 costs through carbon tax. In this respect, a carbon price or an adequate emissions trade system is generally considered the most efficient mechanisms to assess efforts on CCS deployment and reducing CO2 emissions [148,149]. Various carbon tax regulations have recently been put in practice in several regions, such as Australia and the EU, without success. Australia enacted a carbon tax in 2012 that was repealed in July of 2014, whereas the European Emissions Trade System (EU ETS) established a carbon price that has not driven any changes in private capital investment [150]. This noncompetitive price makes cheaper for companies to emit CO2 rather than building the facilities to capture it. According to Maccoy [148], a global carbon pricing tax mainly affects the most carbon intensive industries, whereas performance standards, proposed by the EPA and Canada, force stakeholders to select a low-carbon, and also most expensive, technology. In the case of energy production, the final choice of the lowest cost of fossil-fuel power plant depends not only on the capture cost, but also the fuel price and the overall technology performance and efficiency. Another aspect which has an impact on CCS performance is the CO2 storage regulation. Such laws and regulations were first proposed by regions as Canada, Australia and the EU, including a CCS-specific regulatory framework, a variety of recommendations for future regulatory actions and the EU directive and its accompanying guidance documents. Uncertainties such as CO2 quality for storage, long-term liability, transfer of responsibility and the future price of allowance will all likely prove key features in the global CCS process [151,152]. 6. A new approach for carbon capture: Partial oxy-combustion The energy requirements associated to both the CO2 desorption stage and the O2 separation from air are constraining the industrial deployment of post-combustion and oxy-combustion as CCS technologies, respectively. In this respect, the energy requirement related to the carbon capture process should be as low as possible, 2 GJ/t CO2 being the target to be achieved [153]. A new hybrid concept falling between the above-mentioned CCS technologies can lead to further reductions of the energy consumption of the overall CO2 capture process. This novel approach combines a combustion of fossil-fuels using oxygen-enriched air and a CO2 separation process via chemical absorption using a flue gas with elevated CO2 concentration [154–157]. Partial oxy-combustion emerges as a promising CCS technology for fossil-fuel power plants. The significant reductions on the solvent regeneration stages might make CO2 chemical absorption competitive among other CCS technologies and hence address one of the most important issues hindering the deployment of CO2 chemical absorption for CCS applications. Several works on partial oxy-fuel combustion are reported from the literature. Favre [153] evaluated the technical feasibility of this novel process using the minimal work of separation concept. It consists of the theoretical minimal separation energy in an ideal gaseous binary mixture. Minimal work of extraction and minimal work of concentration were also used. The separation of a component in a gaseous mixture strongly depends of the initial composition of the feed stream [153]. Energy requirements of CO2 separation significantly increased when a more diluted feed stream is used. Based on this phenomena, Favre [153] proposed to relax the constraints regarding oxygen purity towards a moderate oxygen enrichment that reduces the energy consumption of the ASU and facilitates the CO2 separation of a higher concentrated flue gas provided by an enriched-air combustion. Favre [153] studied the generation of low-specified oxygen production via cryogenic and CO2 separation using membranes. The specific energy consumption of the hybrid proposal for CO2 capture was determined by the sum of the two aspect above-mentioned. Favre [153] found an operating optimum ranging between 0.5 and 0.6 O2 molar fraction in the oxidizer that lead to a minimal theoretical separation work of the overall power plant combined with CO2 capture. It should be noted that, according to Favre it is possible to achieve a 35% reduction of the overall energy requirement based on the use of an oxygen-enriched air, typically 40-60%, combined with a CO2 separation process using membranes with a selectivity of 50 or more in CO2/N2 mixtures. Doukelis [154] worked on the technical and economic evaluation of the combination of a fossilfuel combustion using air and oxygen followed by a carbon capture via conventional solvent scrubbing, namely ECO-scrub. This work was focused on a retrofitting alternative for CO2 postcombustion capture ready plants. Two coal-fired power plants were studied, a 330 MWe lignitefired power plant and a 600 MWe hard coal-fired power plant. Air was used during the combustion process and an ASU provided the amount of high purity oxygen required to complete the combustion. A conventional MEA-based chemical absorption was used for CO2 capture. Doukelis [154] concluded that the energy consumption related to oxygen production and CO2 separation were slightly lower in the retrofitted case in comparison with oxy-combustion and conventional post-combustion processes, respectively. The CO2 concentration in the flue gas was increased from 16.3% in the air-fired case to 23.54% in the ECO-scrub case. This fact caused a reduction of the MEA flow-rate of about 15.4%. Nevertheless, oxy-combustion produced higher net electrical efficiency in both plants and thereby a lower total electricity generation cost per electric production. In addition, authors pointed out that this novel approach requires a further capital investment in comparison with both CCS processes separately [153]. Variations of the partial oxy-fuel combustion have been proposed in the literature. Huang [156] proposed the use of a CO2 compression and purification process directly instead of a chemical absorption process to obtain a ready-for-storage CO2 stream, whereas Zanganeh [155] used air as a primary stream to carry the coal towards the boiler and employed oxygen-enriched oxidizer as secondary stream to avoid operational issues regarding high O2 concentrated coal carrier streams. These studies confirm partial oxy-fuel as a potential CCS technology for CO2 abatement in fossilfueled power generation [155]. More recently, a novel Power-to-Gas technology synergized oxy-combustion technique with biomass [158]. A 2 MWth district heating case study was analysed, concluding a raise of the global efficiency up to 78.7%. Hanak [159] proposed a techno-economic analysis of oxy-combustion coal-fired power plant with cryogenic oxygen storage, realizing that benefits of energy storage can only be available at low capital investment. In this case, Implementation of energy storage can improve the daily profit by 3.8–11.6%. Regarding chemical absorption in oxy-combustion operation, Vega [160] proposed a novel study of the oxidative degradation of a novel AMP/AEP blend. Lower degradation rates than MEA as well as less losses were found. Moreover, NH3 emissions were decreased up to 70% under partial oxy-combustion conditions. In a later study, this research group proposed an experimental study on partial oxy-combustion technology in a bench-scale CO2 capture unit, revealing very promising results. The specific energy consumption was reduced up to 4.74 GJ/t CO2 using a 60vol%. CO2 flue gas resulted in 57% reduction compared with post-combustion (Fig. 10) [161]. Fig. 10. Specific energy consumption versus L/G ratios for different CO2 concentrated flue gas. Black points: 15% CO2; Blue curves: 20% CO2; Orange curves: 40% CO2; Grey curves: 60% CO2; and Yellow curves: 60% CO2 (fresh amines). Reproduced with permission from [161]. Further improvements of the overall CO2 separation process under partial oxy-combustion were provided using a relaxing stripping operating conditions [162]. Vega [162] evaluated the stripping performance under variations of the stripping temperature, using a 60% CO2 concentration in the flue gas. Experiments run at 117°C and 118°C provided lower reboiler duty than those experiments run at conventional stripping temperature for MEA 30wt% (120°C). The best case was found at 118°C which reduced the reboiler duty up to 4 GJ/t CO2. This value corresponded with an 11% lower than conventional operation at 120 ˚C – 4.55 GJ/t CO2 [162]. Cau [162] presented a techno-economic analysis for a CO2-free coal-fired power generation by partial oxyfuel and post-combustion CO2 capture. Their analysis proved that this hybrid approach is not feasible for new plants, since the lack of commercial experience will continue to involve a high financial risk. Fig. 11. Specific energy consumption of MEA 30wt% for partial oxy-combustion experiments run at stripping temperatures. Reproduced with permission from [161]. Most of the techno-economic studies used a combination of air with high purity oxygen production which lead to lower benefits in comparison with the direct production of oxygenenriched air as unique comburent. Some advantages have been identified that strengthen this hybrid concept. The main potentialities that should be investigated in order to complete the evaluation of this approach as a real CCS alternative are listed below:  Possibility of reducing energy requirements related to high purity oxygen production by means of a low constraint of oxygen purity: oxygen-enriched air production instead pure oxygen production.  Possibility of using alternative oxygen production technologies such as membranes and adsorption approaches instead of cryogenics, which can lead to a further energy reduction  Strong enhancement of the CO2 absorption process that can promote the CO2 separation from a higher CO2 concentrated flue gas with lower investment than post-combustion absorption. 12 14 16 18 20 22 4 5 6 7 8 L/G ratio Reboiler duty (GJ/t CO 2 ) 120ºC 118ºC 117ºC 115ºC It is clear that research into the CO2 chemical absorption performance under the above-mentioned operating conditions, particularly in a high CO2 concentrated environment, is crucial for strengthening partial oxy-combustion as a CCS technology. An optimal design of the absorption unit from the advantages observed should be evaluated to explore the real options of this approach against post-combustion and oxy-combustion alternatives. 7. Conclusion and future directions The future actions for CO2 emissions mitigation relies on a decarbonization of the energy system. In this respect, the energy perspective for the period 2020-2050 still requires the contribution of CCS technology to meet the reduction targets of the anthropogenic CO2 emissions derived from energy-intensive industries and energy production. The contribution of CCS technologies is foreseen up to 30% of the total greenhouse gas emission reduction by 2050 based on 30-40% CO2 capture cost reduction of this alternative. This fact will produce an important growth on the capacity installed of CCS which were increased from 3 GW in 2020 to 50–250 GW by 2050. This study confirms that a range of solvents for CO2 capture via chemical absorption is available. Furthermore, the current status of chemical absorption development and the activities carried out to overcome CO2 environmental aspects have been addressed. Among the solvents under investigation which are prone to be promising in terms of capture efficiency and energy consumption, the following ones have stood out: piperazine and potassium carbonate investigated by the University of Texas; Piperazine; 2-amino-2-methyl-1-propanol investigated by CSIRO Energy Tech; and the amino acid salts proposed by the University of Twente. Moreover, amine blends seem to be the most promising option since it combines different amines in order to hybridize their overall performance. Novel configurations and process integration into fossil-fuels power plants were also reviewed. In this sense, partial oxy-combustion should be highlighted since high decrease of the regeneration energy was achieved by his proposal – more than 25% from baseline case -. 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