Techno-economic evaluation of advanced IGCC lignite coal fuelled power plants with CO2 capture

The techno-economic evaluation of four novel integrated gasification combined cycle (IGCC) power plants fuelled with low rank lignite coal with CO₂ capture facility has been investigated using ECLIPSE process simulator. The performance of the proposed plants was compared with two conventional IGCC plants with and without CO₂ capture. The proposed plants include an advanced CO₂ capturing process based on the Absorption Enhanced Reforming (AER) reaction and the regeneration of sorbent materials avoiding the need for sulphur removal component, shift reactor and/or a high temperature gas cleaning process. The results show that the proposed CO₂ capture plants efficiencies were 18.5–21% higher than the conventional IGCC CO₂ capture plant. For the proposed plants, the CO₂ capture efficiencies were found to be within 95.8–97%. The CO₂ capture efficiency for the conventional IGCC plant was 87.7%. The specific investment costs for the proposed plants were between 1207 and 1479 €/kW_e and 1620 €/kW_e and 1134 €/kW_e for the conventional plants with and without CO₂ capture respectively. Overall the proposed IGCC plants are cleaner, more efficient and produce electricity at cheaper price than the conventional IGCC process.     

Techno-economic evaluation of a PVAm CO2-selective membrane in an IGCC power plant with CO2 capture

Published data for an operating power plant, the ELCOGAS 315 MWe Puertollano plant, has been used as a basis for the simulation of an integrated gasification combined cycle process with CO₂ capture. This incorporated a fixed site carrier polyvinylamine membrane to separate the CO₂ from a CO-shifted syngas stream. It appears that the modified process, using a sour shift catalyst prior to sulphur removal, could achieve greater than 85% CO₂ recovery at 95 vol% purity. The efficiency penalty for such a process would be approximately 10% points, including CO₂ compression. A modified plant with CO₂ capture and compression was calculated to cost €2320/kW, producing electricity at a cost of 7.6 € cents/kWh and a CO₂ avoidance cost of about €40/tonne CO₂.     

Optimization of energy usage for fleet‐wide power generating system under carbon mitigation options

This article presents a fleet‐wide model for energy planning that can be used to determine the optimal structure necessary to meet a given CO₂ reduction target while maintaining or enhancing power to the grid. The model incorporates power generation as well as CO₂ emissions from a fleet of generating stations (hydroelectric, fossil fuel, nuclear, and wind). The model is formulated as a mixed integer program and is used to optimize an existing fleet as well as recommend new additional generating stations, carbon capture and storage, and retrofit actions to meet a CO₂ reduction target and electricity demand at a minimum overall cost. The model was applied to the energy supply system operated by Ontario power generation (OPG) for the province of Ontario, Canada. In 2002, OPG operated 79 electricity generating stations; 5 are fueled with coal (with a total of 23 boilers), 1 by natural gas (4 boilers), 3 nuclear, 69 hydroelectric and 1 wind turbine generating a total of 115.8 TWh. No CO₂ capture process existed at any OPG power plant; about 36.7 million tonnes of CO₂ was emitted in 2002, mainly from fossil fuel power plants. Four electricity demand scenarios were considered over a span of 10 years and for each case the size of new power generation capacity with and without capture was obtained. Six supplemental electricity generating technologies have been allowed for: subcritical pulverized coal‐fired (PC), PC with carbon capture (PC+CCS), integrated gasification combined cycle (IGCC), IGCC with carbon capture (IGCC+CCS), natural gas combined cycle (NGCC), and NGCC with carbon capture (NGCC+CCS). The optimization results showed that fuel balancing alone can contribute to the reduction of CO₂ emissions by only 3% and a slight, 1.6%, reduction in the cost of electricity compared to a calculated base case. It was found that a 20% CO₂ reduction at current electricity demand could be achieved by implementing fuel balancing and switching 8 out of 23 coal‐fired boilers to natural gas. However, as demand increases, more coal‐fired boilers needed to be switched to natural gas as well as the building of new NGCC and NGCC+CCS for replacing the aging coal‐fired power plants. To achieve a 40% CO₂ reduction at 1.0% demand growth rate, four new plants (2 NGCC, 2 NGCC+CCS) as well as carbon capture processes needed to be built. If greater than 60% CO₂ reductions are required, NGCC, NGCC+CCS, and IGCC+CCS power plants needed to be put online in addition to carbon capture processes on coal‐fired power plants. The volatility of natural gas prices was found to have a significant impact on the optimal CO₂ mitigation strategy and on the cost of electricity generation. Increasing the natural gas prices resulted in early aggressive CO₂ mitigation strategies especially at higher growth rate demands. © 2009 American Institute of Chemical Engineers AIChE J, 2009     

Partial O2-fired coal power plant with post-combustion CO2 capture: A retrofitting option for CO2 capture ready plants

In the work presented in this paper, an alternative process concept that can be applied as retrofitting option in coal-fired power plants for CO₂ capture is examined. The proposed concept is based on the combination of two fundamental CO₂ capture technologies, the partial oxyfuel mode in the furnace and the post-combustion solvent scrubbing. A 330 MW_el Greek lignite-fired power plant and a typical 600 MW_el hard coal plant have been examined for the process simulations. In a retrofit application of the ECO-Scrub technology, the existing power plant modifications are dominated by techno-economic restrictions regarding the boiler and the steam turbine islands. Heat integration from processes (air separation, CO₂ compression and purification and the flue gas treatment) can result in reduced energy and efficiency penalties. In the context of this work, heat integration options are illustrated and main results from thermodynamic simulations dealing with the most important features of the power plant with CO₂ capture are presented for both reference and retrofit case, providing a comparative view on the power plant net efficiency and energy consumptions for CO₂ capture. The operational characteristics as well as the main figures and diagrams of the plant’s heat balances are included.     

Separation and capture of carbon dioxide from CO2/H2 syngas mixture using semi-clathrate hydrates

The relation between anthropogenic emissions of CO₂ and its increased levels in the atmosphere with global warming and climate change has been well established and accepted. Major portion of carbon dioxide released to the atmosphere, originates from combustion of fossil fuels. Integrated gasification combined cycle (IGCC) offers a promising fossil fuel technology considered as a clean coal-based process for power generation particularly if accompanied by precombustion capture. The latter includes separation of carbon dioxide from a synthesis gas mixture containing 40 mol% CO₂ and 60 mol% H₂.A novel approach for capturing CO₂ from the above gas mixture is to use gas hydrate formation. This process is based on selective partition of CO₂ between hydrate phase and gas phase and has already been studied with promising results. However high-pressure requirement for hydrate formation is a major problem.We have used semiclathrate formation from tetrabutylammonium bromide (TBAB) to experimentally investigate CO₂ capture from a mixture containing 40.2 mol% of CO₂ and 59.8 mol% of H₂. The results shows that in one stage of gas hydrate formation and dissociation, CO₂ can be enriched from 40 mol% to 86 mol% while the concentration of CO₂ in equilibrium gas phase is reduced to 18%. While separation efficiency of processes based on hydrates and semi-clathrates are comparable, the presence of TBAB improves the operating conditions significantly. Furthermore, CO₂ concentration could be increased to 96 mol% by separating CO₂ in two stages.     

Techno-economic optimization of IGCC integrated with utility system for CO2 emissions reduction—Maximum power production in IGCC

Environmental legislation, with its increasing pressure on the energy sector to control greenhouse gases, is a driving force to reduce CO₂ emissions. In this paper, pre-combustion CO₂ capture through integration of a site utility system with an integrated gasification combined cycle (IGCC) is investigated as an option to provide a compressed CO₂-rich stream from a process site for sequestration. This work presents a two-step procedure for integration and optimization of a site utility system with an IGCC plant: (i) screening and optimization of IGCC plant performance parameters; (ii) integration and optimization of the utility system of the site with the IGCC plant. In the first step, an optimization approach applies the results of screening studies based on rigorous simulation of the IGCC. Having fixed the inlet fuel flow rate, the IGCC design parameters (including oxygen consumption, diluent flow rate and turbine exit pressure) are optimized for maximum power generation. Energy flows between the IGCC and CO₂ compression train are considered. In the second step, the economic and operating performance of the utility system integrated with the IGCC plant are modeled and optimized for minimum operating cost to find the most appropriate level of integration. In a case study illustrating the approach, 94% of the fuel is gasified; additional power generation offsets the operating costs of pre-combustion CO₂ capture.     

Comparison of solvent performance for CO2 capture from coal-derived flue gas: A pilot scale study

The performance of a proprietary solvent (CAER-B2), an amine-carbonate blend, for the absorption of CO₂ from coal-derived flue gas is evaluated and compared with state-of-the-art 30 wt% monoethanolamine (MEA) under similar experimental conditions in a 0.1 MWth pilot plant. The evaluation was done by comparing the carbon capture efficiency, the overall mass transfer rates, and the energy of regeneration of the solvents. For similar carbon loadings of the solvents in the scrubber, comparable mass transfer rates were obtained. The rich loading obtained for the blend was 0.50 mol CO₂/mol amine compared to 0.44 mol CO₂/mol amine for MEA. The energy of regeneration for the blend was about 10% lower than that of 30 wt% MEA. At optimum conditions, the blend shows promise in reducing the energy penalty associated with using industry standard, MEA, as a solvent for CO₂ capture.     

Comparative assessment of sub-critical versus advanced super-critical oxyfuel fired PF boilers with CO2 sequestration facilities

This work focuses on the techno-economic assessment of bituminous coal fired sub- and super-critical pulverised fuel boilers from an oxyfuel based CO₂ capture point of view. At the initial stage, two conventional power plants with a nominal power output of above 600 MWe based on the above steam cycles are designed, simulated and optimised. Built upon these technologies, CO₂ capture facilities are incorporated within the base plants resulting in a nominal power output of 500 MWe. In this manner, some sensible heat generated in the air separation unit and the CO₂ capture train can be redirected to the steam cycle resulting in a higher plant efficiency. The simulation results of conventional sub- and super-critical plants are compared with their CO₂ capture counterparts to disclose the effect of sequestration on the overall system performance attributes. This systematic approach allows the investigation of the effects of the CO₂ capture on both cycles. In the literature, super-critical plants are often considered for a CO₂ capture option. These, however, are not based on a systematic evaluation of these technologies and concentrate mainly on one or two key features. In this work several techno-economic plant attributes such as the fuel consumptions, the utility usages, the plant performance parameters as well as the specific CO₂ generation and capture rates are calculated and weighed against each other. Finally, an economic evaluation of the system is conducted along with sensitivity analyses in connection with some key features such as discounted cash flow rates, capital investments and plant efficiencies as well as fuel and operating costs.     

Thermodynamic Simulation of CO2 Capture for an IGCC Power Plant using the Calcium Looping Cycle

A CO₂ capture process for an integrated gasification combined cycle (IGCC) power plant using the calcium looping cycle was proposed. The CO₂ capture process using natural and modified limestone was simulated and investigated with the software package Aspen Plus. It incorporated a fresh feed of sorbent to compensate for the decay in CO₂ capture activity during long‐term cycles. The sorbent flow ratios have significant effect on the CO₂ capture efficiency and net efficiency of the CO₂ capture system. The IGCC power plant, using the modified limestone, exhibits higher CO₂ capture efficiency than that using the natural limetone at the same sorbent flow ratios. The system net efficiency using the natural and modified limestones achieves 41.7 % and 43.1 %, respectively, at the CO₂ capture efficiency of 90 % without the effect of sulfation.     

Techno-economic assessment of pulverized coal boilers and IGCC power plants with CO<Subscript>2</Subscript> capture

The current studies on power plant technologies suggest that Integrated Gasification Combined Cycle (IGCC) systems are an effective and economic CO₂ capture technology pathway. In addition, the system in conventional configuration has the advantage of being more “CO₂ capture ready” than other technologies. Pulverized coal boilers (PC) have, however, proven high technical performance attributes and are economically often most practical technologies. To highlight the pros and cons of both technologies in connection with an integrated CO₂ capture, a comparative analysis of ultrasupercritical PC and IGCC is carried out in this paper. The technical design, the mass and energy balance and the system optimizations are implemented by using the ECLIPSE chemical plant simulation software package. Built upon these technologies, the CO₂ capture facilities are incorporated within the system. The most appropriate CO₂ capture systems for the PC system selected for this work are the oxy-fuel system and the postcombustion scheme using Monoethanolamine solvent scrubber column (MEA). The IGCC systems are designed in two configurations: Water gas shift reactor and Selexol-based separation. Both options generate CO₂-rich and hydrogen rich-gas streams. Following the comparative analysis of the technical performance attributes of the above cycles, the economic assessment is carried out using the economic toolbox of ECLIPSE is seamlessly connected to the results of the mass and energy balance as well as the utility usages. The total cost assessment is implemented according to the step-count exponential costing method using the dominant factors and/or a combination of parameters. Subsequently, based on a set of assumptions, the net present value estimation is implemented to calculate the breakeven electricity selling prices and the CO₂ avoidance cost.     

Techno-economic assessment of pulverized coal boilers and IGCC power plants with CO2 capture

The current studies on power plant technologies suggest that Integrated Gasification Combined Cycle (IGCC) systems are an effective and economic CO₂ capture technology pathway. In addition, the system in conventional configuration has the advantage of being more “CO₂ capture ready” than other technologies. Pulverized coal boilers (PC) have, however, proven high technical performance attributes and are economically often most practical technologies. To highlight the pros and cons of both technologies in connection with an integrated CO₂ capture, a comparative analysis of ultrasupercritical PC and IGCC is carried out in this paper. The technical design, the mass and energy balance and the system optimizations are implemented by using the ECLIPSE chemical plant simulation software package. Built upon these technologies, the CO₂ capture facilities are incorporated within the system. The most appropriate CO₂ capture systems for the PC system selected for this work are the oxy-fuel system and the postcombustion scheme using Monoethanolamine solvent scrubber column (MEA). The IGCC systems are designed in two configurations: Water gas shift reactor and Selexol-based separation. Both options generate CO₂-rich and hydrogen rich-gas streams. Following the comparative analysis of the technical performance attributes of the above cycles, the economic assessment is carried out using the economic toolbox of ECLIPSE is seamlessly connected to the results of the mass and energy balance as well as the utility usages. The total cost assessment is implemented according to the step-count exponential costing method using the dominant factors and/or a combination of parameters. Subsequently, based on a set of assumptions, the net present value estimation is implemented to calculate the breakeven electricity selling prices and the CO₂ avoidance cost.     

Cost of energy analysis of integrated gasification combined cycle (IGCC) power plant with respect to CO2 capture ratio under climate change scenarios

This paper presents the results of the cost of energy (COE) analysis of an integrated gasification combined cycle (IGCC) power plant with respect to CO₂ capture ratio under the climate change scenarios. To obtain process data for a COE analysis, simulation models of IGCC power plants and an IGCC with carbon capture and sequestration (CCS) power plant, developed by the United States Department of Energy (DOE) and National Energy Technology Laboratory (NETL), have been adopted and simulated using Aspen Plus. The concept of 20-year levelized cost of energy (LCOE), and the climate change scenarios suggested by International Energy Agency (IEA) are also adopted to compare the COE of IGCC power plants with respect to CO₂ capture ratio more realistically. Since previous studies did not consider fuel price and CO₂ price changes, the reliability of previous results of LCOE is not good enough to be accepted for an economic comparison of IGCC power plants with respect to CO₂ capture ratio. In this study, LCOEs which consider price changes of fuel and CO₂ with respect to the climate change scenarios are proposed in order to increase the reliability of an economic comparison. And the results of proposed LCOEs of an IGCC without CCS power plant and IGCC with CCS (30%, 50%, 70% and 90% capture-mole basis- of CO₂ in syngas stream) power plants are presented.     

Results from trialling aqueous NH3 based post-combustion capture in a pilot plant at Munmorah power station: Absorption

Australia's Commonwealth Scientific and Industrial Research Organization (CSIRO) and Delta Electricity have developed, commissioned and operated an A$7 million aqueous NH₃ based post-combustion capture (PCC) pilot plant at the Munmorah black coal fired power station in Australia. The results from the pilot plant trials will be used to address the gap in know-how on application of aqueous NH₃ for post-combustion capture of CO₂ and other pollutants in the flue gas and explore the potential of the NH₃ process for application in the Australia power sector. This paper is one of a series of publications to report and discuss the experimental results obtained from the pilot plant trials and primarily focuses on the absorption section.The pilot plant trials have confirmed the technical feasibility of the NH₃ based capture process. CO₂ removal efficiency of more than 85% can be achieved even with low NH₃ content of up to 6 wt%. The NH₃ process is effective for SO₂ but not for NO in the flue gas. More than 95% of SO₂ in the flue gas is removed in the pre-treatment column using NH₃. The mass transfer coefficients for CO₂ in the absorber as functions of CO₂ loading and NH₃ concentration have been obtained based on pilot plant data.     

Competitiveness of CO2 capture from an industrial solid oxide fuel cell combined heat and power system in the early stage of market introduction

In this article, it was investigated whether potentially low-cost CO₂ capture from SOFC systems could enhance the penetration of SOFC in the energy market in a highly carbon-constrained society in the mid-term future (up to year 2025). The application of 5 MWe SOFC systems for industrial combined heat and power (CHP) generation was considered. For CO₂ capture, oxyfuel combustion of anode off-gas using commercially available technologies was selected. Gas turbine (GT-) CHP plant was considered to be the reference case.Technical results showed that despite the energy penalties due to CO₂ capture and compression, net electrical and heat efficiencies were nearly identical with or without CO₂ capture. This was due to higher heat recovery efficiency by separating SOFC off-gas streams for CO₂ capture. However, CO₂ capture significantly increased the required SOFC and heat exchanger areas.Economic results showed that for above 40-50 $ t⁻¹ CO₂ price, SOFC-CHP systems were more economical when equipped with CO₂ capture. CO₂ capture also enabled SOFC-CHP to compete with GT-CHP at higher cell stack production costs. At zero CO₂ price, cell stack production cost had to be as low as 140 kW⁻¹ for SOFC-CHP to outperform GT-CHP. At 100 $ t⁻¹ CO₂ price, the cell stack production cost requirement raised to 350 $ kW⁻¹. With CO₂ capture, SOFC-CHP still outperformed GT-CHP at a significantly higher cell stack production cost above 900 $ kW⁻¹.     

High-performance oxygen transport membrane reactors integrated with IGCC for carbon capture

Precombustion carbon capture is an effective strategy to reduce large-scale CO₂ emissions, which is mainly used in the area of integrated gasification combined cycle (IGCC) power plants. Oxygen transport membranes (OTMs) were suggested as the air separation unit to produce high purity oxygen for the gasifier. However, the improvement in efficiency was limited. Here, a new IGCC process is reported based on a robust OTM reactor, where the OTM reactor is used behind the coal gasifier. This IGCC-OTM process fulfills syngas oxidation, H₂ production, and carbon capture in one unit, thus a significant decrease of the energy penalty is expectable. The membrane reactor does not use noble metal components, and exhibits high hydrogen production rates, high hydrogen separation factor (10³–10⁴), and stable performance in a gas mixture mimicking real syngas compositions from a coal gasifier with H₂S concentrations up to 1,000 ppm.     

Modeling and Simulation for Post-Combustion Carbon Dioxide Capture from Power Plant Flue Gas with Economic Analysis

In this study three configurations, viz. conventional MEA, interstage absorber, and interstage absorber with two stripper configuration have been techno-economically evaluated for the optimized result by carrying out simulations using ASPEN PLUS. An economic model defined for carbon capture using 30 wt% MEA to reduce CO₂ in flue gas to 0.5 mol% of 550 MWe coal fired power plant resulted in increase in COE of power plant by 20.6, 17.4, and 15.6 percents for the three configurations, respectively. The CO₂-avoided cost for the three configurations are 65.94, 64.05, and 63.09 ($ /tonne of CO₂ avoided), respectively.     

Progress in carbon dioxide capture and separation research for gasification-based power generation point sources

The purpose of the present work is to investigate novel approaches, materials, and molecules for the abatement of carbon dioxide (CO₂) at the pre-combustion stage of gasification-based power generation point sources. The capture/separation step for CO₂ from large point sources is a critical one with respect to the technical feasibility and cost of the overall carbon sequestration scenario. For large point sources, such as those found in power generation, the carbon dioxide capture techniques being investigated by the Office of Research and Development of the National Energy Technology Laboratory possess the potential for improved efficiency and reduced costs as compared to more conventional technologies. The investigated techniques can have wide applications, but the present research is focused on the capture/separation of carbon dioxide from fuel gas (pre-combustion gas) from processes such as the Integrated Gasification Combined Cycle (IGCC) process. For such applications, novel concepts are being developed in wet scrubbing with physical sorption, chemical sorption with solid sorbents, and separation by membranes. In one concept, a wet scrubbing technique is being investigated that uses a physical solvent process to remove CO₂ from fuel gas of an IGCC system at elevated temperature and pressure. The need to define an “ideal” solvent has led to the study of the solubility and mass transfer properties of various solvents. Pertaining to another separation technology, fabrication techniques and mechanistic studies for membranes separating CO₂ from the fuel gas produced by coal gasification are also being performed. Membranes that consist of CO₂-philic ionic liquids encapsulated into a polymeric substrate have been investigated for permeability and selectivity. Finally, processes based on dry, regenerable sorbents are additional techniques for CO₂ capture from fuel gas. An overview of these novel techniques is presented along with a research progress status of technologies related to membranes and physical solvents.     

Ca-based sorbent looping combustion for CO2 capture in pilot-scale dual fluidized beds

To demonstrate process feasibility of in situ CO₂ capture from combustion of fossil fuels using Ca-based sorbent looping technology, a flexible atmospheric dual fluidized bed combustion system has been constructed. Both reactors have an ID of 100 mm and can be operated at up to 1000 °C at atmospheric pressure. This paper presents preliminary results for a variety of operating conditions, including sorbent looping rate, flue gas stream volume, CaO/CO₂ ratio and combustion mode for supplying heat to the sorbent regenerator, including oxy-fuel combustion of biomass and coal with flue gas recirculation to achieve high-concentration CO₂ in the off-gas. It is the authors' belief that this study is the first demonstration of this technology using a pilot-scale dual fluidized bed system, with continuous sorbent looping for in situ CO₂ capture, albeit at atmospheric pressure. A multi-cycle test was conducted and a high CO₂ capture efficiency (> 90%) was achieved for the first several cycles, which decreased to a still acceptable level (> 75%) even after more than 25 cycles. The cyclic sorbent was sampled on-line and showed general agreement with the features observed using a lab-scale thermogravimetric analysis (TGA) apparatus. CO₂ capture efficiency decreased with increasing number of sorbent looping cycles as expected, and sorbent attrition was found to be another significant factor to be limiting sorbent performance.     

Design and operation of pilot plant for CO2 capture from IGCC flue gases by combined cryogenic and hydrate method

This project is a trial conducted under contract with CO₂CRC, Australia of a new CO₂ capture technology that can be applied to integrated gasification combined cycle power plants and other industrial gasification facilities. The technology is based on combination of two low temperature processes, namely cryogenic condensation and the formation of hydrates, to remove CO₂ from the gas stream. The first stage of this technology is condensation at −55 °C where CO₂ concentration is expected to be reduced by up to 75 mol%. Remaining CO₂ is captured in the form of solid hydrate at about 1 °C reducing CO₂ concentration down to 7 mol% using hydrate promoters. This integrated cryogenic condensation and CO₂ hydrate capture technology hold promise for greater reduction of CO₂ emissions at lower cost and energy demand. Overall, the process produced gas with a hydrogen content better than 90 mol%. The concentrated CO₂ stream was produced with 95-97 mol% purity in liquid form at high pressure and is available for re-use or sequestration. The enhancement of carbon dioxide hydrate formation and separation in the presence of new hydrate promoter is also discussed. A laboratory scale flow system for the continuous production of condensed CO₂ and carbon dioxide hydrates is also described and operational details are identified.     

Sorption-enhanced water gas shift reaction by sodium-promoted calcium oxides

The water gas shift reaction was evaluated in the presence of novel carbon dioxide (CO₂) capture sorbents, both alone and with catalyst, at moderate reaction conditions (i.e., 300-600 °C and 1-11.2 atm). Experimental results showed significant improvements to carbon monoxide (CO) conversions and production of hydrogen (H₂) when CO₂ sorbents are incorporated into the water gas shift reaction. Results suggested that the performance of the sorbent is linked to the presence of a Ca(OH)₂ phase within the sorbent. Promoting calcium oxide (CaO) sorbents with sodium hydroxide (NaOH) as well as pre-treating the CaO sorbent with steam appeared to lead to formation of Ca(OH)₂, which improved CO₂ sorption capacity and WGS performance. Results suggest that an optimum amount of NaOH exists as too much leads to a lower capture capacity of the resultant sorbent. During capture, the NaOH-promoted sorbents displayed a high capture efficiency (nearly 100%) at temperatures of 300-600 °C. Results also suggest that the CaO sorbents possess catalytic properties which may augment the WGS reactivity even post-breakthrough. Furthermore, promotion of CaO by NaOH significantly reduces the regeneration temperature of the former.