Selective Exhaust Gas Recirculation Research Articles

Economic and operational assessment of solar-assisted hybrid carbon capture system for combined cycle power plants

The paper presents a post-combustion CO2 capture process which involves two configurations for enhancing the CO2 separation driving force in the conventional amine-based Carbon Capture System (CCS): a multi-stage membrane module for selective exhaust gas recirculation (SEGR case) and the combination of turbine exhaust gas recirculation with SEGR (EGR + SEGR case). Furthermore, the stripper reboiler in both configurations is integrated with a parabolic trough solar collector field with a 4-h thermal energy storage to provide the required thermal duty for solvent regeneration. Various system components are designed, simulated, and integrated with an economic model to evaluate the system's techno-economic performance across a wide range of loads. The results show that the proposed designs have efficient part-load performance although efficiency degradation is inevitable during partial-loads. A stable supply of solar thermal energy results during the partial operation of NGCC even during night. The EGR + SEGR case represents the case with the lowest levelized cost of electricity and CO2 avoided cost, 81.43 $/MWh and 101.66 $/tonneCO2, among the CCS-equipped designs, which highlight the advantages of this design over baseline and SEGR case. The proposed hybrid system shows promise for significantly decarbonizing fossil-fuel power plants and increasing power sector flexibility.

Thermoexergetic analysis and response optimisation of selective exhaust gas recirculation with solvent-based CO2 capture in a natural gas-fired combined cycle power plant

Thermoexergetic analysis and response optimisation of selective exhaust gas recirculation with solvent-based CO2 capture in a natural gas-fired combined cycle power plant

Study on MCFC-integrated GSCC systems with SEGR in parallel or series and CO2 capture

In this paper, two new molten carbonate fuel cell (MCFC)-integrated gas–steam combined cycle (GSCC) systems with selective exhaust gas recirculation (SEGR) and CO2 capture are proposed and analyzed. The CO2 concentration in the gas turbine emission is increased because CO2 is selectively recycled with the help of SEGR. Molten carbonate fuel cells (MCFCs) are another way to increase CO2 concentration in the gas turbine flue gas by translating only CO2 from the cathode to the anode. In these two new gas–steam combined cycle systems, SEGR connected with MCFC, either in parallel or series, increases CO2 concentration beyond 11%. A gas–steam combined cycle system combined with MCFC and CO2 capture without SEGR is used as the reference system. Aspen Plus software is adopted to build the system models, and the performances of different systems are discussed and compared. The research results reveal that for the MCFC-integrated gas–steam combined cycle system with SEGR in series and CO2 capture, the CO2 concentration of gas turbine exhaust increases to 11.72% and the thermal efficiency is 56.29% when the overall CO2 capture rate is 88.16%, which is 1.13% higher than that of the reference system; for the MCFC-integrated gas–steam combined cycle system with SEGR in parallel and CO2 capture, the CO2 concentration of gas turbine exhaust increases to 14.15% and the thermal efficiency is 56.62%, which is 1.46% higher than that of the reference system. Furthermore, the economic analysis results show that the economic performances of new systems are mainly influenced by MCFC cost and will be gradually improved with the decrease in the MCFC cost.

Advancing power plant decarbonization with a flexible hybrid carbon capture system

Carbon dioxide capturing from natural gas-fired power plants is challenging due to high flow rate and the low carbon dioxide concentration of flue gas. This is an emerging field where many concepts and scientific principles are still in development. In this paper, a novel design is proposed for decarbonizing a natural gas-fired combined cycle power plant using a solar-assisted hybrid membrane-amine carbon capture and storage system. The design incorporates a solar field with thermal energy storage integrated with the capture plant reboiler along with multi-stage carbon dioxide selective membrane modules for selective exhaust gas recirculation (SEGR) combined with exhaust gas recirculation (EGR) to increase the concentration of Carbon dioxide in the flue gas. It is hypothesized that the proposed design could enhance the performance of the power plant integrated with carbon capture in terms of flexibility and sustainability. In this regard, a comprehensive process modeling and simulation framework is developed to accurately investigate the interactions between different components of the integrated process. The results show that the carbon dioxide concentration in the flue gas increases from 3.9 mol% in the conventional power plant to 10.87 mol% in the EGR + SEGR case (26 % of flue gas to EGR and 50 % to SEGR) and increases to 18.08 mol% by the SEGR case (76 % of flue gas to SEGR). Solar thermal energy is an efficient solution for reducing or eliminating the need for steam extraction for the stripper reboiler, resulting in a significant increase in net power output compared to the non-solar cases. The proposed designs lead to a 19.4 % increase in system power output in the SEGR case and a 13.8 % increase in the EGR + SEGR case compared to the baseline case. Also, the specific reboiler duty and required packing material volume in the absorber and stripper are significantly improved in the proposed designs. Moreover, the power plant carbon intensity in the proposed designs can be reduced by up to 10.3 %. The EGR + SEGR case offers an optimal solution as it requires a significantly smaller membrane area, approximately 71 % smaller membrane area compared to SEGR. The proposed designs and analysis have the potential to contribute significantly to the decarbonization of fossil-fueled power plants and enhance the sustainability and flexibility of the power sector.

Simulation and Economic Investigation of CO2 Separation from Gas Turbine Exhaust Gas by Molten Carbonate Fuel Cell with Exhaust Gas Recirculation and Selective Exhaust Gas Recirculation

The paper presents a simulation investigation of using a molten carbonate fuel cell (MCFC) combined with exhaust gas recirculation (EGR) or selective exhaust gas recirculation (SEGR) to reduce CO2 emission from the gas turbine in order to cope with climate change problem. EGR or SEGR can be used to concentrate the low-concentration CO2 in gas turbine exhausts. The CO2 concentration is then raised further by adding gas turbine exhaust to the MCFC’s cathode. The suggested gas–steam combined cycle system paired with MCFC and CO2 collection without EGR is contrasted with two novel gas–steam combined cycle systems integrated with MCFC, EGR, or SEGR with CO2 capture (the reference system). The thermal efficiency of the gas–steam combined cycle systems’ integrated MCFC, EGR and SEGR with CO2 collection is 56.08%, which is 1.3% higher than the reference system. The cost of CO2 avoided in the new system with SEGR will be equal to that of the system with the MEA technique for CO2 capture if the MCFC cost is reduced to 904.4 USD/m2.

Performance analysis of selective exhaust gas recirculation integrated with fogging cooling system for gas turbine power plants

Selective exhaust gas recirculation (S-EGR) is a proposed alternative for enhancing the CO2 capture units applied in power plants. Most previous studies focused on the correlation between S-EGR and CO2 capture unit efficiency. Nevertheless, the S-EGR system without pre-cooling considerably influences the gas turbine output power due to its relatively high temperature. Hence this study aims to investigate the influence of the integration of fogging cooling systems with S-EGR on gas turbine performance. This combination could reduce the adverse effects of the S-EGR system in power plants as well as increase the effectiveness of the fogging cooling system in hot, humid regions. A three-dimensional Euler–Lagrange CFD model is employed to simulate the mutual effect between S-EGR and fogging cooling systems under different operation conditions. The impact of output condition from combined fogging and S-EGR system (cooled CO2 enriched air) on the gas turbine performance is then investigated. Results illustrate that applying the fogging cooling approach after mixing the inlet air and S-EGR reduces the moisture content of the inlet air and augments the cooling capacity of the fogging system. When the CO2-enriched stream is pre-cooled to the same ambient temperature, the fogging system outlet temperature drops more, especially at high S-EGR ratios. Applying the S-EGR system could increase the inlet mixture density (CO2-enriched air) by about 12% at an S-EGR ratio of 35%, which is increased to 18% after incorporating the fogging cooling system. Regarding gas turbine performance, using CO2-enriched air without pre-cooling leads to a significant deterioration in performance, notably at high S-EGR ratios. On the other hand, the amalgamation of S-EGR with fogging cooling could boost gas turbine output power from 11.7 to 19.2%, with an efficiency gain of half a percentage point.

Investigation into simulating Selective Exhaust Gas Recirculation and varying Pressurized Hot Water temperature on the performance of the Pilot-scale Advanced CO2 Capture Plant with 40 wt(%) MEA

The concentration of an aqueous solution of amine affects the solvent regeneration energy requirement in the Post-combustion CO2 Capture (PCC) process. Therefore, this study investigates the performance of the impact of Selective Exhaust Gas Recirculation (S-EGR) under the influence of 40 wt(%) MEA i.e. 10 % above the benchmark Monoethanolamine (MEA) concentration and at 90 % CO2 capture efficiency due to its potential to reduce the Normalized Specific Reboiler Duty (N-SRD) of the CO2 capture process. The experimental research work was carried out at the United Kingdom Carbon Capture Storage Research Centre - Pilot-scale Advanced CO2 Capture Technology (UKCCSRC-PACT) National Core Facility, UK. The S-EGR was proposed as a means of CO2 enhancement at the inlet of the absorber column to expedite the driving force of CO2 absorption and consequently reduce the N-SRD. CO2 concentrations from 5.0 to 9.9 vol(%) of CO2 were studied. Also, this experiment studied the influence of the Pressurized Hot Water (PHW) inlet temperature at the reboiler on the performance of the CO2 capture process that includes the CO2 recovery rate, CO2 loadings and N-SRD of the Solvent-based CO2 Capture Plant (SCCP) in order to study the variation of N-SRD with varying reboiler thermal inlet temperature at 9.0 vol(%) CO2.It is found that a pilot-scale CO2 capture process under the influence of simulated S-EGR reduces the N-SRD by 25.1 % under the test condition at 6.6 vol(%) CO2. This test condition was observed to have lower N-SRD as with regards to the other tests with different CO2 concentrations, below and above which the N-SRD begins to lose its value. It was also established that within the boundary of the process conditions used in these tests, the impact of the PHW temperature on the CO2 capture efficiency increases with increasing the PHW temperature, but at the detriment of N-SRD, which begins to increase above 125 °C despite more CO2 being captured.

Part load operation of natural gas fired power plant with CO2 capture system for selective exhaust gas recirculation

• Model of gas power plant with CO 2 capture for selective gas recycle is presented. • Gas recycle offers stable combustion, higher CO 2 content, low gas flow and reboiler duty. • Part-load operation of gas plant at 80, 60, 40% is analyzed for the parallel and hybrid case. This work investigates base and part load operation of natural gas combined cycle power plant integrated with post-combustion CO 2 capture plant and selective exhaust gas recirculation scheme. Decarbonizing of natural gas combined cycle power plant is complex due to the higher flue gas flow rate with the least CO 2 content ~ 3–4 vol% with residual 20% O 2 and 77% N 2 content. Therefore, the effect of series, parallel and hybrid selective exhaust gas recirculation is examined, a concept where selectively CO 2 can be recycled back and mixed into the ambient air to the inlet feed of the compressor thereby reducing the flue gas flow rate and enhancing CO 2 content at the inlet of capture plant. The study is novel in a way that part-load performance at 80, 60 and 40% for parallel and hybrid scheme of selective exhaust gas recirculation is analyzed through process simulation in Aspen Plus for 606 MW commercial-scale natural gas combined cycle power plant coupled with an amine-based CO 2 capture plant. It is found that the simulation results of power plant and CO 2 capture plant model agrees well with the experimental results. Further, the performance results show the viability of base and part load operation of natural gas combined cycle power plant integrated with CO 2 capture plant by enhancing the CO 2 concentration for hybrid configuration to approximately 19 vol%. For parallel configuration, CO 2 content increases to around 13–14 vol% at 70% recirculation ratio in comparison to 6.6 vol% for simple EGR at 35% ratio. It is found that the selective exhaust gas recirculation offers more stable combustion by maintaining O 2 content at 19 vol% at combustor inlets for parallel and hybrid cases and the flue gas flow rate reduces to 68 and 70%, respectively thus reducing the size of the capture plant. The specific reboiler duty for hybrid, parallel, and series configuration reduces to 3.19, 3.25, and 3.31 MJ/kg CO 2 , respectively in comparison to 3.54 MJ/kg CO 2 for base case natural gas combined cycle power plant coupled with MEA-based CO 2 capture unit. Whereas for 80 to 40% load change, the specific reboiler duty drops from 1.78% to 1.14% for parallel and hybrid configurations, respectively. In conclusion, hybrid selective exhaust gas recirculation configuration shows less efficiency penalty from base load to 40% part load and results in a decrease in specific reboiler duty in comparison to parallel configuration. Therefore, the study is innovative in an aspect that part-load performance at 80, 60 and 40% is performed, and results show a similar pattern as of baseload operation.

Selective Exhaust Gas Recycling in Gas Turbines with CO2 capture: A comprehensive technology assessment

Modern gas turbines operate with large amounts of excess air for cooling and dilution of the combustion gases, in order to maintain gas turbine blade integrity. Selective recycling of CO2 into the gas turbine compressor inlet, also referred as Selective Exhaust Gas Recirculation (SEGR), can reduce the large volumetric flow rate through a CO2 capture system caused by the gas turbine excess air requirements, by 70 - 77%. It also increases CO2 concentrations to 14-18 vol% from 3-4% vol, increasing the driving force for post-combustion capture systems. This paper provides a comprehensive assessment of the concept and presents research outcomes from the UK-funded SELECT project, including power plant and process modelling, techno-economic assessments, pilot-scale gas turbine experimental work and experimental combustion tests on a representative combustor. Using an integrated model of turbomachinery, power cycles and a generic post-combustion CO2 capture technology with a 30%wt MEA solvent, we show that a reduction of up to 50% of the absorber of the capture plant – the most capital intensive part of the process – can be achieved. The compressor and gas turbine operate without any significant deviation from their design point, and a marginal increase of 0.5% point in the net electrical efficiency can be achieved. Pilot-scale testing - conducted at the Pilot Scale Advanced Capture Technologies (PACT) facilities at the University of Sheffield - show that CO2 injection at the compressor inlet of a 100 kW micro gas turbine (mGT) connected to a 1 tonne per day CO2 capture plant reduces net electrical efficiency by 1-2 %point. This is caused by lower flame temperatures, and, unlike in larger gas turbines, the control system of the micro gas turbine. Combustion tests at Cardiff University’s Gas Turbine Research Centre (GTRC) in a pilot-scale high-pressure generic premixed swirl burner, representative of modern dry-low emissions (DLR) gas turbine burners, show the effect of CO2 as diluent on the operational premixed CH4/air flame stability, chemical kinetics and measured exhaust gas composition. CO2 acts as a combustor inhibitor, causing downstream migration of the premixed flame zone, leading to eventual blow-off, instability and extinction, requiring a change in the operation equivalence ratio. The effect of adding CO2 leads to a reduction in the adiabatic flame temperature due to thermal quenching, which results in higher CO emissions and smaller thermal NOx emissions. Increasing pressure has a significant reducing effect on CO emissions, yet it results in higher NOx production, which may require mitigation if this trend is found to continue towards pressures approaching that of the F-class gas turbine. Finally, a conceptual design assessment of a regenerative adsorption wheel with structured adsorbents is proposed for the selective recycling of CO2 in combined cycle gas turbine (CCGT) power plants. It has the advantage of a relatively small pressure drop to reduce the derating of the gas turbine compared to selective CO2 membrane systems. An equilibrium model of a rotary adsorber with commercially available activated carbon adsorbents shows that four rotary wheels of 24 m diameter and 2 m length would be required in an 820MW CCGT plant. A reduction of 50% in the mass of adsorbent would be possible with an adsorbent with a higher capacity, such as Zeolite X13, with upstream dehydration of the flue gases.

Rotary Adsorption: Selective Recycling of CO2 in Combined Cycle Gas Turbine Power Plants

A conceptual design assessment shows that the use of structured adsorbents in a regenerative adsorption wheel is technically feasible for the application of selective exhaust gas recirculation (SEGR) in combined cycle gas turbine (CCGT) power plants. As the adsorber rotates, CO2 is selectively transferred from a flue gas stream to an ambient air stream fed to the gas turbine compressor, increasing the CO2 concentration and reducing the flow rate of the fraction of the flue gases treated in a post-combustion CO2 capture system. It imposes an estimated pressure drop of 0.25 kPa, unlike a pressure drop of 10 kPa reported for selective CO2 membrane systems, preventing a significant derating of the gas turbine. An equilibrium model of a rotary adsorber with commercially available activated carbon evaluates the inventory of the adsorbent and sizes the wheel rotor. Two rotary wheels of 24 m diameter and 2 m length are required per gas turbine—heat recovery steam generator train to achieve an overall CO2 capture level of 90% in a CCGT power plant (ca. 820 MWe) with SEGR “in parallel” to the capture plant. Two to five rotary wheels are required for a configuration with SEGR “in series” to the capture plant. A reduction of 50% in the mass of the adsorbent would be possible with Zeolite 13X instead of activated carbon, yet the hydrophilicity of zeolites are detrimental to the capacity and upstream dehydration of the flue gases is required. A parametric analysis of the equilibrium properties provides guidelines for adsorbent development. It suggests the importance of balancing the affinity for CO2 to allow the regeneration of the adsorbent with air at near ambient pressure and temperature, to minimise the inventory of the adsorbent within practical limits. An adsorbent with a saturation capacity of 8 mol/kg, a heat of adsorption from 24 to 28 kJ/mol CO2 and a pre-exponential factor of the equilibrium constant from 2 × 10–6 to 9 × 10–6 kPa−1 would result in an inventory below 200 kg, i.e., approximately the limit for the use of a single rotary wheel system.

Process-integrated design of a sub-ambient membrane process for CO2 removal from natural gas power plants

This paper proposes an advanced sub-ambient membrane process that applies an improved CO2/N2 selectivity under cold temperatures for CO2 removal from a natural gas combined-cycle power plant. The use of a large excess of combustion air in a natural gas power plant results in a relatively diluted CO2 exhaust gas, typically by 3–4%, which makes it difficult to achieve an energy-efficient CO2 capture. The sub-ambient membrane process using exhaust gas recirculation and/or selective exhaust gas recirculation is designed to concentrate the CO2 from 4 to 6–10%. In addition, the heat integration of liquefied natural gas (LNG) regasification not only provides a nearly free cold energy source for producing a cold processing environment, it also maximizes the full potential of the heat recovery. Among the different membrane designs proposed, an integrated process using all design options demonstrates the lowest CO2 capture cost at $ 57/tCO2, which is a 55.1% reduction in capture costs, and a 70.1% decrease in parasitic load compared to an early configuration. A sensitivity analysis was conducted to understand the impact of the membrane performance, namely, the CO2 permeance and CO2/N2 selectivity, on the process design and economics of the CO2 capture process considered herein, through which guidelines for the development of membrane materials and a conceptual insight into the design and optimization of a membrane-based capture process can be obtained.

Experimental investigation of the impacts of selective exhaust gas recirculation on a micro gas turbine

Selective exhaust gas recirculation (S-EGR) is an option proposed to augment the CO2 content in the flue gases of gas-fired systems, facilitating integrated post-combustion CO2 capture. However, issues such as flame instabilities and increases in unburned species require careful analysis. The performance of a micro-gas turbine under simulated S-EGR conditions is evaluated here. Maximum flue gas CO2 concentrations of 8.4 and 10.1 vol% were achieved at power outputs of 100 and 60 kWe, respectively; a 4–7 times increase in CO2 content compared to the baseline cases – similar to what can be achieved with S-EGR systems. Impacts on the operational performance of the system were assessed, together with the resulting CO, unburned hydrocarbon and nitrogen oxide (NOx) emission trends. The electrical efficiency reduced slightly under S-EGR conditions and emissions of unburned and partially oxidised species increased, especially at lower loads, where incomplete combustion effects were more prominent. The rotational speed of the engine decreased under S-EGR conditions as a result of the change in the oxidiser properties, with the compressor discharge temperatures also decreasing slightly. Furthermore, NOx emissions were lower in S-EGR scenarios due to the expected lower flame temperatures, which leads to reduced thermal NOx production.

Selective exhaust gas recirculation in combined cycle gas turbine power plants with post-combustion CO2 capture

In the context of the process intensification of Post-combustion Carbon Capture (PCC), Selective Exhaust Gas Recirculation (SEGR) in Natural Gas-fired Combined Cycle (NGCC) plants, a concept where CO2 is selectively recycled to increase concentration and reduce flow rates of the flue gas, is analysed. SEGR operated either in parallel or in series with a downstream PCC system increases CO2 concentration beyond 14 vol% and maintains oxygen levels in the combustor to approximately 19 vol%, well above the 16 vol% limit reported for non-selective Exhaust Gas Recirculation (EGR). Process modelling shows that the current class of gas turbine engines can operate without a significant deviation in the compressor and in the turbine performance. Compressor inlet temperature and CO2 concentration in the working fluid are the two critical parameters affecting the gas turbine net power output and efficiency. A higher turbine exhaust temperature allows the generation of additional steam in the HRSG. This results in an increase in net power output of approximately 42 MW (5.2%) and 18 MW (2.3%), and in net thermal efficiency of 0.55%point and 0.83%point, for the investigated configurations with SEGR in parallel and SEGR in series, respectively. With 30 wt% aqueous monoethanolamine scrubbing technology, SEGR leads to operation and cost benefits. SEGR in parallel with 70% recirculation, 97% selective CO2 transfer efficiency and 96% PCC efficiency results in a reduction of 46% in packing volume and 5% in specific reboiler duty, compared to air-based combustion CCGT with PCC, and of 10% in packing volume and 2% in specific reboiler duty, compared to 35% EGR. SEGR in series operating at 95% selective CO2 transfer efficiency and 32% PCC efficiency results in a reduction of 64% in packing volume and 7% in specific reboiler duty, compared to air-based CCGT with PCC, and of 40% in packing volume and 4% in specific reboiler duty, compared to 35% EGR. On selecting a technology for SEGR applications, CO2 selectivity, pressure drop and heat transfer flow rate are the operating parameters with a larger effect on the power plant performance with SEGR. It is important to minimise oxygen leakages from the air into the flue gas, minimise heat transfer that would otherwise increase CO2-enriched air temperature at compressor inlet, and minimise pressure drop, e.g. a 1 kPa pressure drop results in gas turbine derating of 2 MW (0.7%).

Techno-economic analysis of a hybrid CO2 capture system for natural gas combined cycles with selective exhaust gas recirculation

This work analyses the implementation of CO2 capture in natural gas combined cycle (NGCC) power plants using a hybrid system integrated by an amine scrubbing plant and a CO2 selective membrane. In this configuration, the membrane unit operates at close to atmospheric pressure and it is used to selectively recycle CO2 back to the inlet of the compressor, therefore increasing the CO2 content of the flue gas entering the capture system. A novel integration between the amine capture plant and the selective membrane is analysed here, which aims at exploiting the benefits of both the parallel and series selective exhaust gas recirculation (S-EGR) existing options. The mass and energy balances performed on this system indicate that the new configuration generates a flue gas with a CO2-enhanced concentration of 18%vol., which leads to a decrease in the energy demand in the reboiler by 6% with respect to an amine scrubbing system coupled to a conventional NGCC plant without S-EGR. Moreover, a reduction of 77% is achieved in the gas flowrate fed to the absorber of the amine plant, thus significantly reducing its size and cost. The calculated net electrical efficiency of the plant is 50.3%, which is 0.5 net percentage points higher than that of a conventional NGCC with amine-based capture and slightly lower than that of a reference plant with exhaust gas recirculation (EGR). These values are dependent on the pressure drop associated with the membrane system, which has a large influence on the energy balance of the plant. Therefore, higher efficiency improvements can be achieved if membrane module designs with reduced pressure drop are used. A techno-economic evaluation reveals that the cost of the membrane system has a strong effect on the capital costs of the plant and thus, on the cost of electricity and the cost of CO2 avoided. These values vary between $81.9 and $93.9 per MWh and $82.6 and $121.8 per tonne of CO2 avoided, respectively, for the S-EGR cases studied at a reference capacity factor of 0.85. A sensitivity analysis shows that it is necessary to reduce the costs of the reference hybrid S-EGR system in order to make it competitive against current benchmark options. Therefore, further ongoing development towards membrane units with high CO2 permeance, limited pressure drop and reduced costs is particularly interesting for the S-EGR system studied in this work. The obtained results also indicate the targeted values of these parameters that can make the cost of the S-EGR configuration to be below that of conventional systems with amine capture and EGR options for CO2 capture in NGCC power plants under different scenarios.

Selective-exhaust gas recirculation for CO2 capture using membrane technology

Membranes can potentially offer low-cost CO2 capture from post-combustion flue gas. However, the low partial pressure of CO2 in flue gases can inhibit their effectiveness unless methods are employed to increase their partial pressure. Selective-Exhaust Gas Recirculation (S-EGR) has recently received considerable attention. In this study, the performance of a dense polydimethylsiloxane (PDMS) membrane for the separation of CO2/N2 binary model mixtures for S-EGR application was investigated using a bench-scale experimental rig. Measurements at different pressures, at different feeding concentrations and with nitrogen as sweep gas revealed an average carbon dioxide permeability of 2943 ± 4.1%RSD Barrer. The bench-scale membrane module showed high potential to separate binary mixtures of N2 and CO2 containing 5–20% CO2. The permeability was slightly affected by feed pressures ranging from 1 to 2.4bar. Furthermore, the separation selectivity for a CO2/N2 mixture of 10%/90% (by volume) reached a maximum of 10.55 at 1.8bar. Based on the results from the bench-scale experiments, a pilot-scale PDMS membrane module was tested for the first time using a real flue gas mixture taken from the combustion of natural gas. Results from the pilot-scale experiments confirmed the potential of the PDMS membrane system to be used in an S-EGR configuration for capture of CO2.

Process Analysis of Selective Exhaust Gas Recirculation for CO2 Capture in Natural Gas Combined Cycle Power Plants Using Amines

Postcombustion 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 (ACP) using monoethanolamine (MEA) 30 wt % was simulated using gCCS (gPROMS). It was benchmarked against an unabated NGCC system, a conventional NGCC coupled with an ACP (NGCC + carbon capture and storage (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 (COE) for the parallel S-EGR system varies from 82.1 to 90.0 $/MWhe for the scenarios considered, with the cost of CO2 avoided (COA) being in the range of 79.7–105.1 $/ton 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.

Making gas‐CCS a commercial reality: The challenges of scaling up

AbstractSignificant reductions in CO2 emissions are required to limit the global temperature rise to 2°C. Carbon capture and storage (CCS) is a key enabling technology that can be applied to power generation and industrial processes to lower their carbon intensity. There are, however, several challenges that such a method of decarbonization poses when used in the context of natural gas (gas‐CCS), especially for solvent‐based (predominantly amines) post‐combustion capture. These are related to: (i) the low CO2 partial pressure of the exhaust gases from gas‐fired power plants (∼3‐4%vol. CO2), which substantially limits the driving force for the capture process; (ii) their high O2 concentration (∼12‐13%vol. O2), which can degrade the capture media via oxidative solvent degradation; and (iii) their high volumetric flow rates, which means large capture plants are needed. Such post‐combustion gas‐CCS features unavoidably lead to increased CO2 capture costs. This perspective aims to summarize the key technologies used to overcome these as a priority, including supplementary firing, humidified systems, exhaust gas recirculation and selective exhaust gas recirculation. These focus on the maximum CO2 levels achievable for each, as well as the electrical efficiencies attainable when the capture penalty is taken into account. Oxy‐turbine cycles are also discussed as an alternative to post‐combustion gas‐CCS, indicating the main advantages and limitations of these systems together with the expected electrical efficiencies. Furthermore, we consider the challenges for scaling‐up and deployment of these technologies at a commercial level to enable gas‐CCS to play a crucial role in a low‐carbon future. © 2017 The Authors. Greenhouse Gases: Science and Technology published by Society of Chemical Industry and John Wiley & Sons, Ltd.