Relevant bibliographies by topics / MEA amine CO2 and H2S capture process

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Academic literature on the topic 'MEA amine CO2 and H2S capture process'

Author: Grafiati
Published: 4 June 2021
Last updated: 1 February 2022

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Journal articles on the topic "MEA amine CO2 and H2S capture process"

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Soriano, Allan N., Adonis P. Adornado, Angelica A. Pajinag, Diana Joy F. Acosta, Niel M. Averion, Gilfred M. Leron, and Vergel C. Bungay. "Multicriterial Analysis of Simulated Process of Post-Combustion Capture of Pure H2S and Mixtures of H2S and CO2 Using Single and Blended Aqueous Alkanolamines." ASEAN Journal of Chemical Engineering 15, no. 1 (October 1, 2015): 72. http://dx.doi.org/10.22146/ajche.49695.

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The paper evaluates the performance of the nine selected alkanolamines, namely, monoethanolamine (MEA), diethanolamine (DEA), monomethylethanolamine (MMEA), aminoethylethanolamine (AEEA), diisopropanolamine (DIPA), triethanolamine (TEA), dimethylethanolamine (DMEA), N-methyldiethanolamine (MDEA), and piperazine (PZ) for post-combustion capture of pure hydrogen sulfide (H2S) and mixtures of hydrogen sulfide and carbon dioxide (CO2) at different solvent mass flows: 500, 750, and 1000 kg/h using Aspen Plus® Version 7.2. The objective of the paper is to select the best chemical absorbent for each different criterion: percent H2S removal, percent H2S solvent carrying capacity, percent H2S retained in the lean solvent, percent CO2 and H2S removal, percent CO2 and H2S solvent carrying capacity, percent CO2 and H2S retained in the lean solvent. Based from the obtained results, piperazine is an absorbent that has a good potential for use as a single amine or in mixtures with other amines for capture of pure H2S and mixtures of H2S and CO2.
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Karunarathne, Sumudu S., Dag A. Eimer, and Lars E. Øi. "Physical Properties of MEA + Water + CO2 Mixtures in Postcombustion CO2 Capture: A Review of Correlations and Experimental Studies." Journal of Engineering 2020 (March 5, 2020): 1–17. http://dx.doi.org/10.1155/2020/7051368.

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The knowledge of physicochemical properties of a mixture of amine, water, and CO2 is beneficial in evaluating the postcombustion CO2 capture process and process equipment design. This study reviews the literature of density, viscosity, and surface tension measurements with the evaluated measurement uncertainties and proposed correlations for monoethanol amine (MEA), water, and CO2 mixtures. Adequate research has been performed to measure and develop correlations for pure MEA and aqueous MEA mixtures, but further studies are required for CO2-loaded aqueous MEA mixtures. The correlations fit measured properties with an acceptable accuracy, and they are recommended to use in process equipment design, mathematical modelling, and simulations of absorption and desorption.
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Ma, Yanqing, Yitao Liao, Yi Su, Baojie Wang, Yong Yang, Dong Ji, Hongwei Li, Huairong Zhou, and Dongliang Wang. "Comparative Investigation of Different CO2 Capture Technologies for Coal to Ethylene Glycol Process." Processes 9, no. 2 (January 22, 2021): 207. http://dx.doi.org/10.3390/pr9020207.

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The coal to ethylene glycol (CTEG) process has drawn much attention due to the serious conflict between supply and demand of ethylene glycol in China. However, it is inevitably accompanied by the problem of high CO2 emissions. Carbon capture is one of the most promising potential effective ways to address this issue. However, the CTEG process, integrated with carbon capture technology, will lead to energy and economic penalties. Thus, a comprehensive evaluation of CTEG process with different CO2 capture technologies is urgently needed. This study analyzed the technoeconomic performance of four CO2 capture alternatives for the CTEG process: Rectisol, mono-ethanol amine (MEA), chilled ammonia process (CAP) and dimethyl carbonate (DMC) technologies. Results show the energy consumption of CO2 capture of the Rectisol process is the lowest, 1.88 GJ/tCO2, followed by the DMC process, 2.10 GJ/tCO2, the CAP process, 3.64 GJ/tCO2, and the MEA process, 5.20 GJ/tCO2. The CO2 capture cost of the Rectisol process is lowest, CNY 169.5/tCO2, followed by the DMC process, CNY 193.2/tCO2, the CAP process CNY 232.6/tCO2, and the MEA process CNY 250.5/tCO2. As the Rectisol technology has the best comprehensive performance, it is the best option for CTEG industry in comparison with the MEA, CAP, and DMC technologies.
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Ho Choi, Jeong, Jong Tak Jang, Chan Young Park, Soung Hee Yun, Won Hee Jo, Jung-Hyun Lee, and Yeo Il Yoon. "The Piperidine-H2O-CO2 System for Sequestering Highly Concentrated CO2." Science of Advanced Materials 13, no. 5 (May 1, 2021): 755–70. http://dx.doi.org/10.1166/sam.2021.3895.

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The post-combustion capture (PCC) process using amines is one of the most representative technologies for separating CO2 from huge CO2 emisions. However, the achievement of reasonable costs for capturing CO2 requires continuous studies on absorbent development, process optimization, and energy saving. Among these, the absorbent development is the most essential factor in reducing the operating cost and equipment cost of the PCC process. In this study, piperidine (PD) solution is used as an alternative absorbent to overcome the disadvantage of commercial monoethanolamine (MEA) solution. The absorption rate, absorption capacity and regeneration energy of PD solution were measured to confirm its performance as an alternative absorbent. It was found that PD solution shows key advantages, compared with MEA solution. First, the overall mass transfer of CO2 in PD solution was 2.69 times faster than in MEA solution at 313 K. Second, PD solution was capable of absorbing 1.5 times more of CO2 than MEA solution. Third, the reboiler heat duty of PD solution showed 1.16 times better energy-efficiency than that of MEA because the sensible heat of PD was 75.8 kJ·mol−1 lower than that of MEA. From these results, PD solution is deemed to be a good alternative absorbent to replace MEA solution.
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Dinca, Cristian, Adrian Badea, and Horia Necula. "High Performance of the CFBC Pilot Plant with CO2 Chemical Absorption by Optimizing the Absorber Parameters." Advanced Materials Research 746 (August 2013): 3–8. http://dx.doi.org/10.4028/www.scientific.net/amr.746.3.

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The objective of this paper consists to identify the influence of absorption process temperature and pressure on the energy requirement of the CO2 chemical capture process. The study aimed to reducing CO2 emissions from coal combustion process in the circulating fluidized bed combustion (CFBC). The post-combustion CO2 capture process was analyzed using primary amine MEA in the following conditions: the ratio L/G was varied between 0.45..1.6 kgliquid/kggas keeping constant the flue gas flow and varying the solvent flow between 500 .. 1 600 kg/h. The CO2 capture process efficiency was maintained constant around 90%. For a concentration of 30% MEA in solution, it was observed that when the absorber solution temperature increasing from 32 to 49 °C, the amount of heat required for the solvent regeneration increased from 2.1 to 3.3 GJ/tCO2 according to the solvent pressure and flue gas pressure respectively. On the other hand, for varying the absorber solvent pressure in the range 1.1 .. 2.1 atm, the heat required by the process was not significantly influenced. Considering the same variation of the absorber solvent temperature, the rich loading solvent was increased from 0.43 to 0.57 mol CO2/mol MEA and consequently the MEA capacity of CO2 absorption from 0.3 to 0.422 molCO2/mol MEA.
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Chen, Pao-Chi, Hsun-Huang Cho, Jyun-Hong Jhuang, and Cheng-Hao Ku. "Selection of Mixed Amines in the CO2 Capture Process." C 7, no. 1 (February 24, 2021): 25. http://dx.doi.org/10.3390/c7010025.

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In order to select the best mixed amines in the CO2 capture process, the absorption of CO2 in mixed amines was explored at the required concentrations by using monoethanolamine (MEA) as a basic solvent, mixed with diisopropanolamine (DIPA), triethanolamine (TEA), 2-amino-2-methyl-1-propanol (AMP), and piperazine (PZ). Here, a bubble column was used as the scrubber, and a continuous operation was adopted. The Taguchi method was used for the experimental design. The conditional factors included the type of mixed amine (A), the ratio of the mixed amines (B), the liquid feed flow (C), the gas-flow rate (D), and the concentration of mixed amines (E). There were four levels, respectively, and a total of 16 experiments. The absorption efficiency (EF), absorption rate (RA), overall mass transfer coefficient (KGa), and scrubbing factor (ϕ) were used as indicators and were determined in a steady-state by the mass balance and two-film models. According to the Taguchi analysis, the importance of the parameters and the optimum conditions were obtained. In terms of the absorption efficiency (EF), the absorption rate (absorption factor) (RA/ϕ), and the overall mass transfer coefficient (KGa), the order of importance is D > E > A > B > C, D > E > C > B > A, and D > E > C > A > B, respectively, and the optimum conditions are A1B4C4D3E3, A1B3C4D4E2, A4B2C3D4E4, and A1B1C1D4E1. The optimum condition validation results showed that the optimal values of EF, RA, and KGa are 100%, 30.69 × 10−4 mol/s·L, 1.540 l/s, and 0.269, respectively. With regard to the selection of mixed amine, it was found that the mixed amine (MEA + AMP) performed the best in the CO2 capture process.
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Choi, Yoon-Seok, Deli Duan, Shengli Jiang, and Srdjan Nešić. "Mechanistic Modeling of Carbon Steel Corrosion in a Methyldiethanolamine (MDEA)-Based Carbon Dioxide Capture Process." Corrosion 69, no. 6 (January 3, 2013): 551–59. http://dx.doi.org/10.5006/0695.

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A predictive model was developed for corrosion of carbon steel in carbon dioxide (CO2)-loaded aqueous methyldiethanolamine (MDEA) systems, based on modeling of thermodynamic equilibria and electrochemical reactions. The concentrations of aqueous carbonic and amine species (CO2, bicarbonate [HCO3−], carbonate [CO32−], MDEA, and protonated MDEA [MDEAH+]) as well as pH values in the MDEA solution were calculated. The water chemistry model showed a good agreement with experimental data for pH and CO2 loading, with an improved correlation upon use of activity coefficients. The electrochemical corrosion model was developed by modeling polarization curves based on the given species's concentrations. The required electrochemical parameters (e.g., exchange current densities, Tafel slopes, and reaction orders) for different reactions were determined from experiments conducted in glass cells. Iron oxidative dissolution, HCO3− reduction, and MDEAH+ reduction reactions were implemented to build a comprehensive model for corrosion of carbon steel in an MDEA-CO2-water (H2O) environment. The model is applicable to uniform corrosion when no protective films are present. A solid foundation is provided for corrosion model development for other amine-based CO2 capture processes.
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Wang, Junyao, Liangxu Liu, Xuelan Zeng, and Kaixiang Li. "Solar-assisted CO2 capture with amine and ammonia-based chemical absorption：A comparative study." Thermal Science, no. 00 (2020): 149. http://dx.doi.org/10.2298/tsci191222149w.

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Intensive energy penalty caused by CO2 separation process is a critical obstacle for retrofitting power plant with carbon capture technology. Therefore, the concept of utilizing solar energy to assist solvent regeneration for post-combustion carbon capture power plant is proposed recently as a promising pathway to compensate the efficiency reduction derived from CO2 capture process. However, the feasibility of solar-assisted post-combustion (SPCC) technologies largely depends on the types of CO2 absorbent, categories of solar thermal collectors, areas of solar field and the integration of thermal energy storage system. Therefore, this paper conducts a comparative analysis on MEA-based and NH3-based SPCC power plants employing two types of solar collectors, i.e the vacuum tube (VT) and the parabolic through collector (PTC), with climate data of Tianjin City. Levelized costs of electricity and cost of CO2 removed are comparatively studied for both SPCC configurations. Results show that the proposed SPCC configurations are economically viable when the price of vacuum the tube (VT) is lower than 86.64$/m2 and 117.29$/m2 for the MEA-based and NH3-based SPCC power plant respectively. Meanwhile, the price of PTC should be less than 111.12$/m2 for the MEA-based and 114.51$/m2 for the NH3-based SPCC power plant. It is indicated that employing the VT for chilled NH3-based SPCC power plant offers a promising approach to reduce the energy penalty with attractive economic performance.
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Lee, Yunje, Junghwan Kim, Huiyong Kim, Taesung Park, Hailian Jin, Hoonsik Kim, Sangdo Park, and Kwang Soon Lee. "Operation of a Pilot-Scale CO2 Capture Process with a New Energy-Efficient Polyamine Solvent." Applied Sciences 10, no. 21 (October 29, 2020): 7669. http://dx.doi.org/10.3390/app10217669.

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A new blending recipe of a polyamine-based solvent for capturing post-combustion CO2 was proposed, and its performance and characteristics were investigated using a pilot-scale carbon capture process (PCCP). The proposed solvent is a blend of three types of amines and was designed to separate the solvent roles into those of a main amine, auxiliary amine, and reaction-rate-enhancing amine. Polyamine 3,3′-iminobis (N, N-dimethylpropylamine) was selected as the main amine given its ability to capture large amounts of CO2. 2-Amino-2-methyl-1-propanol was used as the auxiliary amine, with piperazine added as the reaction-rate-enhancing amine. This solvent was tested in a PCCP that can handle 150 Nm3/h of flue gas. The proposed solvent was found to operate stably while consuming substantially lower reboiler duty than the monoethanolamine (MEA) 30 mass% solvent.
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Li, Yuan, Qi Min Wang, and Pei Bin Wang. "Evaluation of Post-Combustion CO2 Capture Technologies." Advanced Materials Research 734-737 (August 2013): 1881–86. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.1881.

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This paper evaluates the results of two recent studies of advanced amine-based, post-combustion CO2 capture plant designs. The first study was conducted by the IEA Greenhouse Gas R&D Programme (IEA GHG), while the second study was conducted by Parsons for the US DOEs National Energy Technology Laboratory (NETL). Fluors improved monoethanolamine (MEA) process, known as the Econamine FG PlusSM technology, is utilised for both studies. Cost and performance estimates for both pulverized coal and natural gas-fired combined cycle plants are summarized. Differences between the design bases and assumptions for the two studies are discussed. The Econamine FG PlusSM technology, as an improved process in amine-based post-combustion CO2 capture described in this paper is leading to lower increases in the cost of electricity (COE). Both the DOE/Parsons and IEA GHG studies show that the increase is now down to 42 to 43% from as high as 60 to 70% indicated from previous studies for PC plants with CO2 capture.
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Dissertations / Theses on the topic "MEA amine CO2 and H2S capture process"

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El, Gemayel Gemayel. "Integration and Simulation of a Bitumen Upgrading Facility and an IGCC Process with Carbon Capture." Thèse, Université d'Ottawa / University of Ottawa, 2012. http://hdl.handle.net/10393/23274.

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Hydrocracking and hydrotreating are bitumen upgrading technologies designed to enhance fuel quality by decreasing its density, viscosity, boiling point and heteroatom content via hydrogen addition. The aim of this thesis is to model and simulate an upgrading and integrated gasification combined cycle then to evaluate the feasibility of integrating slurry hydrocracking, trickle-bed hydrotreating and residue gasification using the Aspen HYSYS® simulation software. The close-coupling of the bitumen upgrading facilities with gasification should lead to a hydrogen, steam and power self-sufficient upgrading facility with CO2 capture. Hydrocracker residue is first withdrawn from a 100,000 BPD Athabasca bitumen upgrading facility, characterized via ultimate analysis and then fed to a gasification unit where it produces hydrogen that is partially recycled to the hydrocracker and hydrotreaters and partially burned for power production in a high hydrogen combined cycle unit. The integrated design is simulated for a base case of 90% carbon capture utilizing a monoethanolamine (MEA) solvent, and compared to 65% and no carbon capture scenarios. The hydrogen production of the gasification process is evaluated in terms of hydrocracker residue and auxiliary petroleum coke feeds. The power production is determined for various carbon capture cases and for an optimal hydrocracking operation. Hence, the feasibility of the integration of the upgrading process and the IGCC resides in meeting the hydrogen demand of the upgrading facility while producing enough steam and electricity for a power and energy self-sufficient operation, regardless of the extent of carbon capture.
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Ramasubramanian, Kartik. "CO2 (H2S)-SELECTIVE MEMBRANES FOR FUEL CELL HYDROGEN PURIFICATION AND FLUE GAS CARBON CAPTURE:AN EXPERIMENTAL AND PROCESS MODELING STUDY." The Ohio State University, 2013. http://rave.ohiolink.edu/etdc/view?acc_num=osu1374193903.

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Conference papers on the topic "MEA amine CO2 and H2S capture process"

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Atsonios, Kostantinos, Antonios Koumanakos, Kyriakos D. Panopoulos, Aggelos Doukelis, and Emmanuel Kakaras. "Techno-Economic Comparison of CO2 Capture Technologies Employed With Natural Gas Derived GTCC." In ASME Turbo Expo 2013: Turbine Technical Conference and Exposition. American Society of Mechanical Engineers, 2013. http://dx.doi.org/10.1115/gt2013-95117.

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Carbon Capture and Storage can either concern the removal of carbon as CO2 in flue gases (post-combustion option) or before its combustion in a Gas Turbine (pre-combustion option). Among the numerous CO2 capture technologies, amine scrubbing (MEA and MDEA), physical absorption (Selexol™ and Rectisol™) and H2 separator membrane reactors are investigated and compared in this study. In the pre-combustion options, the final fuel combusted in the GT is a rich-H2 fuel. Process simulations in ASPEN Plus™ showed that the case of H2 separation with Pd-based membranes has the greatest performance as far as the net efficiency of the energy system is concerned. The economic assessment reveals that the technology is promising in terms of cost of CO2 avoided, provided that the current high membrane costs are reduced.
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Sipo¨cz, Nikolett, and Mohsen Assadi. "Combined Cycles With CO2 Capture: Two Alternatives for System Integration." In ASME Turbo Expo 2009: Power for Land, Sea, and Air. ASMEDC, 2009. http://dx.doi.org/10.1115/gt2009-59595.

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As Carbon Capture and Storage (CCS) technology has grown as a promising option to significantly reduce CO2 emissions, system integration and optimization claim an important and crucial role. This paper presents a comparative study of a gas turbine cycle with post-combustion CO2 separation using an amine-based absorption process with Monoethanolamine (MEA). The study has been made for a triple pressure reheated 400 MWe natural gas-fuelled combined cycle (NGCC) with exhaust gas recirculation (EGR) to improve capture efficiency. Two different options for the energy supply to the solvent regeneration have been evaluated and compared concerning plant performance. In the first alternative heat is provided by steam extracted internally from the bottoming steam cycle while in the second option an external biomass-fuelled boiler was utilized to generate the required heat. With this novel configuration the amount of CO2 captured can be even more than 100% if the exhaust gas from the bio-fuelled boiler is mixed and cleaned together with the main exhaust gas flow from the combined cycle. In order to make an unprejudiced comparison between the two alternatives, the reduced steam turbine efficiency has been taken into consideration and estimated, for the alternative with internal steam extraction. The cycles have been modelled in the commercial heat and mass balance programme IPSEpro™ using detailed component models. Utilizing EGR can double the CO2 content of the exhaust gases and reduce the energy need for the separation process by approximately 2%-points. Using an external biomass-fuelled boiler as heat source for amine regeneration, turns out to be an interesting option due to high CO2 capture effectiveness. However the electrical efficiency of the power plant is reduced compared to the option with internal steam extraction. Another drawback with the external boiler is the higher investment costs but nevertheless, it is flexibility due to the independency from the rest of the power generation system represents a major operational advantage.
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Zhang, Zhien, Yunfei Yan, Junlei Wang, Li Zhang, Yanrong Chen, and Shunxiang Ju. "Analysis of CO2 Capture From Power-Plant Flue Gas Using the Membrane Gas Absorption (MGA) Method." In ASME 2015 Power Conference collocated with the ASME 2015 9th International Conference on Energy Sustainability, the ASME 2015 13th International Conference on Fuel Cell Science, Engineering and Technology, and the ASME 2015 Nuclear Forum. American Society of Mechanical Engineers, 2015. http://dx.doi.org/10.1115/power2015-49026.

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Currently membrane gas absorption (MGA) is a novel approach for gas separation. In the present work, a wide-ranging 2D mathematical model for CO2 absorption from the N2/CO2 mixture is proposed. Single solvents [H2O, ethylenediamine (EDA), diethanolamine (DEA), monoethanolamine (MEA), piperazine (PZ)] and blended solvents [DEA/PZ] were used as the absorbents. The non-wetting mode for the membrane contactor was considered in the calculations. The effects of gas concentration and velocity, and liquid concentration and velocity on CO2 removal were observed. The simulation results were verified with the experimental data showing a good agreement. The modeling results indicate that gas concentration and velocity have a negative effect on the capture process, while liquid concentration and velocity enhance CO2 capture. Also, it is noted that PZ has the best absorption performance than other single absorbents. The chemical solvents are much better than the physical solvent for the absorption of CO2. For mixed absorbents based on amine solutions, the CO2 removal efficiency could be about 20% higher than that of the single solutions. Thus, this model could provide the optimum operating conditions for acid gas absorption in the hollow fiber membrane module. It is also proved that the MGA approach exhibits a good potential in power-plant waste gas purification.
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Chavez, Rosa-Hilda, Javier de J. Guadarrama, and Abel Hernandez-Guerrero. "A Study Numerical Simulation of Post Combustion CO2 Capture Process." In ASME 2009 International Mechanical Engineering Congress and Exposition. ASMEDC, 2009. http://dx.doi.org/10.1115/imece2009-10502.

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Amine absorption technology, in particular that based on the Monoethanolamine (MEA) process, is considered to be viable for low pressure flue gas CO2 capture because of the MEA-CO2 fast reaction rate. MEA absorption processes are associated with high capital and operating cost because a significant amount of energy is required for solvent regeneration and severe operating problems are present such as corrosion and solvent loss and degradation. The overall objective of this study is to evaluate the feasibility of obtaining the heat required for amine absorption for a particular recovery of carbon dioxide. Comparisons among cases were performed to determine the best operating conditions for CO2 capture. An analysis of the lean loading and recovery percent were carried out as well as the different absorber and stripper combinations by using the chemical processes simulator.
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Chavez, Rosa-Hilda, Javier de J. Guadarrama, and Abel Hernandez-Guerrero. "Exergy Analysis of the Sequestration of CO2 Emissions." In ASME 2008 International Mechanical Engineering Congress and Exposition. ASMEDC, 2008. http://dx.doi.org/10.1115/imece2008-66534.

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Carbon dioxide capture from flue gas using amine-based CO2 capture technology requires huge amounts of energy mostly in the form of heat. The overall objective of this study is to evaluate the feasibility of obtaining the heat required for amine absorption for a particular recovery of carbon dioxide for a given a set of equipment specifications and operating conditions from the process and to develop a model that simulates the removal of CO2 using Monoethanolamine (MEA) absorption from flue gas and design a process that will minimize the energy of CO2 capture with Aspen Plus™ will be used. A very useful procedure for analyzing a process is by means of the Second Law of Thermodynamics. Thermodynamic analyses based on the concepts of irreversible entropy increase have frequently been suggested as pointers to sources of inefficiency in chemical processes.
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Cohen, Stuart M., Michael E. Webber, and Gary T. Rochelle. "The Impact of Electricity Market Conditions on the Value of Flexible CO2 Capture." In ASME 2012 International Mechanical Engineering Congress and Exposition. American Society of Mechanical Engineers, 2012. http://dx.doi.org/10.1115/imece2012-88119.

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Carbon dioxide (CO2) capture with amine scrubbing at coal-fired power plants can remove 90% of the CO2 from flue gas, but operational energy requirements reduce net electrical output by 20–30%. Temporarily reducing the load on energy intensive components of the amine scrubbing process could temporarily increase power output and allow additional electricity sales when prices are high. Doing so could entail additional CO2 emissions, or amine solvent storage can be utilized to allow increased power output without additional CO2 emissions. Price-responsive flexible capture is studied for $0–200/tCO2 and $2–11/MMBTU natural gas using a nominal 500 MW coal-fired facility in the 2010 Electric Reliability Council of Texas (ERCOT) grid. CO2 capture systems use a 7 molal monoethanolamine (MEA) solvent. Venting additional CO2 while increasing electrical output provides significant benefit only at $30–60/tCO2 and when natural gas prices exceed $4/MMBTU. Solvent storage can improve profitability with CO2 capture at higher CO2 emissions penalties, but primarily at low-to-moderate natural gas prices when power plant capacity factor is less than 90%.
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Diego, Maria Elena, Jean-Michel Bellas, and Mohamed Pourkashanian. "Process Analysis of Selective Exhaust Gas Recirculation for CO2 Capture in Natural Gas Combined Cycle Power Plants Using Amines." In ASME Turbo Expo 2017: Turbomachinery Technical Conference and Exposition. American Society of Mechanical Engineers, 2017. http://dx.doi.org/10.1115/gt2017-64387.

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Post-combustion CO2 capture from natural gas combined cycle (NGCC) power plants is challenging due to the large flow of flue gas with low CO2 content (∼3–4%vol.) that needs to be processed in the capture stage. A number of alternatives have been proposed to solve this issue and reduce the costs of the associated CO2 capture plant. This work focuses on the selective exhaust gas recirculation (S-EGR) configuration, which uses a membrane to selectively recirculate CO2 back to the inlet of the compressor of the turbine, thereby greatly increasing the CO2 content of the flue gas sent to the capture system. For this purpose, a parallel S-EGR NGCC system (53% S-EGR ratio) coupled to an amine capture plant using MEA 30%wt. was simulated using gCCS (gPROMS). It was benchmarked against an unabated NGCC system, a conventional NGCC coupled with an amine capture plant (NGCC+CCS), and an EGR NGCC power plant (39% EGR ratio) using amine scrubbing as the downstream capture technology. The results obtained indicate that the net power efficiency of the parallel S-EGR system can be up to 49.3% depending on the specific consumption of the auxiliary S-EGR systems, compared to the 49.0% and 49.8% values obtained for the NGCC+CCS and EGR systems, respectively. A preliminary economic study was also carried out to quantify the potential of the parallel S-EGR configuration. This high-level analysis shows that the cost of electricity for the parallel S-EGR system varies from 82.1–90.0 $/MWhe for the scenarios considered, with the cost of CO2 avoided being in the range of 79.7–105.1 $/tonne CO2. The results obtained indicate that there are potential advantages of the parallel S-EGR system in comparison to the NGCC+CCS configuration in some scenarios. However, further benefits with respect to the EGR configuration will depend on future advancements and cost reductions achieved on membrane-based systems.
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