Gas-fired Combined Cycle Power Plants Research Articles

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

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.

Energy analysis of novel hybrid solar and natural gas combined cycle plants

The integration of renewable energy sources into standard energy systems is a fundamental step in the energy transition. The purpose of the paper is to investigate the integration of solar energy into a traditional natural gas-fired combined cycle power plant, while also evaluating the impact of intercooling, in terms of energy efficiency and CO2 emissions. Solar energy is integrated into the gas turbine topping cycle through parabolic trough collectors, with the aim of preheating the air leaving the compressor. Two additional configurations have been compared, based on one- and two-stage intercooled compression. The goal is to find the optimal hybrid configuration. To this purpose, a thermodynamic analysis of the overall plant has been performed, and a numerical model has been specifically developed to simulate the solar field. The model has been integrated into Thermoflex™ to simulate the overall combined cycle. Solar-to-electric conversion efficiency, based on solar energy input alone, has received specific attention to make relevant comparisons with conventional concentrated solar based power plants. Furthermore, net electric efficiency, electrical power share due to solar energy integration, natural gas savings, and CO2 emissions have been investigated. The solar-to-electric conversion efficiency has been shown to increase with the compression ratio while the net electric efficiency decreases. To achieve a trade-off between the need for high net electric efficiency and high solar integration, an optimization based on the Pareto front was carried out. The selected configuration consists of one intercooling stage and a compression ratio of 17.9, resulting in a solar conversion efficiency of 33%, which is much better than traditional solar-only power plants. Additionally, the net electric efficiency is 69.5%. To test this configuration under actual operating conditions, a one-year simulation was carried out in two cities with different climates: Messina and Torino. An average annual solar-to-electric efficiency of around 32% can be achieved in both cities, with natural gas savings of 7.7% and 5.8% per year for Messina and Torino, respectively.

Identifying Economic and Clean Strategies to Provide Electricity in Remote Rural Areas: Main-Grid Extension vs. Distributed Electricity Generation

The policy decision of extending electric power transmission lines to connect a remote area to a primary grid vs. developing local electricity generation resources must be informed by studies considering both alternatives’ economic and environmental outcomes. Such analysis must also consider the uncertainty of several factors such as fuel prices, the cost and performance of renewable and conventional power generation technologies, and the value of environmental benefits. This paper presents a method for this analysis, making two main contributions to the literature. First, it shows how to characterize the two alternatives (i.e., main-grid extension vs. local power generation) in detail for precise quantification of their capital and operating costs while guaranteeing that they are both adequate to meet forecast demand and operating reserves. Second, it shows how to properly account for the economic and environmental implications of renewable energy intermittency and uncertainty through the optimization of capital investments and hourly operations. The method is illustrated by applying this analysis method to Saudi Arabia, where the government is struggling to outline a strategy to meet residential and commercial loads reliably and sustainably in the country’s remote, scattered, isolated areas. To meet this demand, the Saudi government is considering two main alternatives: (1) extending the primary power transmission grid; or (2) installing an optimal combination of off-grid distributed generation (DG) resources, including solar PV, wind, diesel, oil, heavy fuel oil, and Li-ion batteries, to generate the electricity locally. Results suggest that under most scenarios of capital costs, fuel prices, and costs of air pollution, developing a microgrid with a large share of wind and solar power is more cost-effective than extending a primary grid 150 km or more away. Extending a primary grid powered by gas-fired combined-cycle power plants is more economical only if the load is not very high, the distance is not more than 350 km, and oil prices are relatively high compared to natural gas.

Experimental study on CO2 separation using hydrophobic deep eutectic solvent based supported liquid membranes

Deep eutectic solvents (DESs) have been proposed as a viable and more sustainable solvent for CO2 capture, owing to their low volatility and tunable properties. In this work, polymer membranes were combined with hydrophobic DESs to prepare supported liquid membranes (DES-SLMs), and the potential of using SLMs for CO2/N2 separation was investigated. COSMO-RS model simulations, bond energy analysis as well as stability tests were used to select the polymeric porous support. Hydrophobic polyvinylidene fluoride (PVDF) with a nominal pore size of 0.1 μm was chosen to support three selected hydrophobic DESs. The gas permeabilities through three selected DES-SLMs were experimentally determined, where the thymol-coumarin (1:1) based SLM showed the best performance with a CO2 permeability of 175.0 Barrer and selectivity of 30.2 at room temperature. The separation capability was further improved by mixing the DES with traditional physical absorbents. In addition, the effects of water presence in the gas phase on the DES-SLM were investigated. The membrane was physically stable, but the ideal selectivity of CO2/N2 through the membrane deteriorated with time on steam. By predicting the permeabilities of CO2 and N2 through traditional organic liquid based SLMs, the prospects of developing DESs for SLM applications were demonstrated. Finally, an advanced membrane capture process for a natural gas-fired combined cycle (NGCC) power plant was studied with process simulation and economic analysis, where the SLMs are used to purify the CO2 product.

Prediction of NOx emissions from gas turbines of a combined cycle power plant using an ANFIS model optimized by GA

Combined cycle power plants, which combine gas and steam turbines, have negative impacts on surrounding populations and structures. Control of NOx emissions is an important issue for these gas-fired power plants. Accurate estimation of NOx emissions is critical for developing incinerators and reducing the environmental impact of existing plants. The objective of this study is to model ANFISGA and estimate NOx emissions from a natural gas-fired combined cycle power plant using emission monitoring system (PEMS) data. First, Adaptive Neuro Fuzzy Inference System (ANFIS) models were developed using fuzzy C-Means (FCM). Then, the parameters were optimized using a genetic algorithm (GA) to reduce the error. The proposed ANFISGA system was created, trained, and tested with PEMS datasets. The developed models were compared using several statistical performance criteria, including correlation coefficient (R2), mean squared error (MSE), error mean (EM), root mean square error (RMSE), standard deviation of error (STD), and mean absolute percentage error (MAPE). The obtained results show that the coefficient of determination varies between 0.79933 and 0.90363 for the data separated into test and training data with different rates. The minimum values of the criteria MSE, RMSE, EM, STD, and MAPE were found to be 24.8379, 4.9838, 3.4625e-05, 4.9839, and 5.1660, respectively, for the training data. The minimum values of these criteria for the test data were 26.5961, 5.1571, 0.065696, 5.157, and 5.3695, respectively. The collected results show that the proposed ANFISGA models have high potential for NOx prediction. Thus, the results show that GA has a great impact on the performance of ANFIS training and significantly improves the predictive accuracy of the model.

Prediction of de-NOx performance using monolithic SCR catalyst under load following operation of natural gas-fired combined cycle power plants

As variable renewable energy expands, natural gas-fired combined cycle (NGCC) power plants are expected to provide important functions for grid stabilization such as quick start-up, shutdown, and load following. However, transient operation of NGCC significantly increases the NO2 content of NOX in the exhaust gas and reduces de-NOx performance of selective catalytic reduction (SCR) with ammonia injection. The denitrification performance of SCR depends on transient mechanisms such as adsorption of ammonia in the catalyst and redox reactions on the catalyst surface. This study evaluates whether de-NOX performance can be maintained during expected operational fluctuations for grids with a high penetration of variable renewable energy. Simulations involving a modified de-NOX reaction scheme have been developed and validated for various NGCC exhaust gas compositions expected in both steady state and transient operation using a commercial, monolithic SCR catalyst. Results show that sudden output load changes cause a decrease in SCR catalyst performance due to changes in gas composition and temperature outpacing the adsorption/desorption of ammonia in the catalyst. It was found that adjusting the injection amount of ammonia several minutes prior to the output load change was effective in maintaining de-NOX performance.

Kinetic model of SCR catalyst-based de-NOx reactions including surface oxidation by NO<sub>2</sub> for natural gas-fired combined cycle power plants

Kinetic model of SCR catalyst-based de-NOx reactions including surface oxidation by NO<sub>2</sub> for natural gas-fired combined cycle power plants

Effect of Drum Pressure on Flow Accelerated Corrosion in Gas Fired Combined Cycle Power Plant: A Case Study and Literature Review

The dissolution of ferrous ions from the protective oxide layer and/or base metal by corrosion with the assistance of turbulent flow is called flow accelerated corrosion (FAC). Flow accelerated corrosion is the most common and continuous corrosion reaction in combined cycle power plants (CCPP). Heat recovery steam generator (HRSG) drum pressure fluctuation and/or turbulent drum water greatly influences the FAC of drum and economizer. This kind of FAC was investigated in the low-pressure drum (LPD) and low-pressure economizer (LPE) of a 210 MW gas-fired combined cycle power plant (Four-unit HRSG & GT) with an air-cooled condenser (ACC). Severe FAC was observed due to the fluctuation of pressure in the LPD with respect to time. As a result, huge amounts of soluble iron (Fe2+) and insoluble (Fe3+) was found in all running HRSG’s LPD water. Due to pressure fluctuations in the LPD, a protective oxide layer (mostly magnetite), as well as the base metal, were corroded from the LPD and LPE even after carefully maintaining recently developed water cycle chemistry in this CCPP. Severe leakage was found in the LPE due to corrosion. The actual reason for the problem was found to be a malfunctioning steam-control valve in the turbine unit’s LP system. This valve was malfunctioning by suddenly opening to 100% and then closing to around 10% continuously. This malfunction creates enormous pressure drops in both the LPD and LPE units. It is understood that water turbulence is the main cause of FAC affecting the LDP and LPE. This assessment is based on chemical laboratory analysis and physical inspection. There was no non-destructive testing (NDT) performed in this study. The severe FAC happened in four days and for this reason, HRSG and steam turbines were shut down. Maintenance work on the control valve and flushing of the LPD and LPE successfully resolved the FAC problem. One week later, LPE leakage was found on the unit-3 HRSG and as reported in this study this was also found to be the result of FAC. From this case study, it is concluded that not only water quality but also water turbulence can create severe FAC problem.

Assessing the potential of molten carbonate fuel cell-based schemes for carbon capture in natural gas-fired combined cycle power plants

This work explores two configurations of natural gas-fired combined cycles (NGCC) with molten carbonate fuel cells (MCFC) for CO2 capture. Special attention is devoted to the selection of MCFC operating conditions (trade-off between CO2 capture and voltage losses), heat integration scheme, fuel use and CO2 purification. Two schemes are considered: (i) in the first “integrated” scheme, MCFC modules are installed between the gas turbine and the heat recovery steam generator (HRSG) to maximize the efficiency of the integrated power plant; (ii) in the second “non-integrated” layout, the MCFC is located downstream of the HRSG and a regenerative heat exchanger is designed to preheat cathode reactants up to the MCFC working temperature. This study includes a full techno-economic analysis of the two layouts based on a preliminary sizing of the key-components, and a sensitivity analysis on the CO2 utilization factor. Compared to a benchmark amine scrubbing process, the “integrated” configuration shows considerably better performance (Specific Primary Energy Consumption for CO2 Avoided - SPECCA = 0.31 MJ kgCO2-1; Cost of CO2 avoided - CCA = 50 $ tCO2−1), whereas the “non-integrated” solution shows higher energy penalties but similar CO2 avoidance cost (SPECCA = 2.4 MJ kgCO2−1; CCA = 76 $ tCO2−1).

Advancing CO2 Capture from Natural Gas Combined Cycle Power Plants with Piperazine Scrubbing

Carbon dioxide capture and storage is widely recognized as an essential technology for limiting the global temperature rise to 2 °C by the end of the century. Technology development efforts so far focus on coal-fired power plants and other industrial sources with relatively high CO2 partial pressures. However, natural gas is increasingly used in power generation because of its abundance and low greenhouse gas impacts among the fossil fuels. For deep decarbonization that is required in the future, fossil fuels with CCS continue to play a relevant role in scenarios that balance cost of energy with climate impacts. Carbon capture from natural gas sources has been an ongoing interest to CO2 Capture Project (CCP) and its members from the oil and gas industry. This paper describes the work related to solvent-based natural gas carbon capture sponsored by CCP and pilot studies performed in collaboration with University of Texas at Austin researchers. The collaboration with University of Texas at Austin (UT) is aimed at demonstrating the application of an aqueous piperazine solution-a second-generation solvent-in a pilot plant. The goal is to test CO2 separation from synthetic flue gas representative of the exhausts from natural gas-fired combined cycle power plant (i.e. ~4 mol% CO2). The low CO2 concentration in NGCC flue gas is considered to be a challenge for many capture technologies. This work tested the performance of 5m piperazine in the UT pilot plant at a range of operating conditions, including solvent loadings, gas and liquid flow rates, assessing two different absorber configurations. High CO2 capture rates above 90% were confirmed. The pilot test results were used to verify and extend the range of applicability of the thermodynamic model developed by UT. This work increases the confidence for the application of the process models to design CCS processes for low CO2 concentrations. The model’s predictions of the pilot plant tests at low concentrations are now as accurate and reliable as those for higher CO2 concentrations where much of the data have been collected until now. Further pilot tests at NCCC are being designed to supplement the model evaluation data set for NGCC flue gas as well as to address questions related to oxidation/corrosion and cooling scheme optimization for NGCC applications.

Techno-Economic Comparison of Combined Cycle Power Plants with Pre-Combustion Co2 Capture Via Two Different Reforming Methods: Chemical Looping Reforming and Gas Switching Reforming

This paper focuses on the techno-economic comparison of gas-fired combined cycle power plants with CO2 capture and two reforming methods, chemical looping reforming (CLR) and gas-switching reforming (GSR). The overall processes are denoted as CLR-CC and GSR-CC respectively. The net electrical efficiency of the CLR-CC and GSR-CC is 42.1% and 46.2% respectively. Anyhow, with improvements in the gas turbine configuration, the net electrical efficiency improves by 2.5%. GSR-CC has a higher CO2 avoidance (>95%). The levelised cost of electricity (LCOE) for CLR-CC is lower than that of GSR-CC for based load operation of the power plant. Anyhow, GSR-CC provides flexibility in terms of output, electricity or pure H2. The capital requirement in the GSR-CC is higher due to the requirement of multiple standalone reactors to maintain a steady flow of the syngas produced from the GSR. The LCOE of both the processes is sensitive to the fuel cost. Further improvements in the GSR-CC process can make the process competitive to post- combustion capture.

Influence of various carbon capture technologies on the performance of natural gas-fired combined cycle power plants

Carbon capture and storage (CCS) technology has been studied actively in recent years to address global warming. This paper aimed to make a consistent comparison of different capture technologies applied to the natural gas-fired combined cycle (NGCC). Multiple power plant systems based on a standard NGCC using three different carbon capture technologies (post-combustion, pre-combustion, and oxycombustion) were proposed, and their net performance was compared. The optimal pressure ratio of the oxy-combustion technology system was obtained. The variations in the net cycle performance of the three systems were compared using the specific CO2 capture. The net power of the post-combustion capture scheme is lower than that of all other systems, but it has the highest efficiency. However, its biggest disadvantage is a much lower CO2 capture rate than the oxy-combustion capture which exhibits nearly 100 % capture rate. The conclusion is that the oxy-combustion capture would provide both the highest net efficiency and power output if a high capture rate of over 92 % was required.

Analysis of Combined Cycle Power Plants with Chemical Looping Reforming of Natural Gas and Pre-Combustion CO2 Capture

In this paper, a gas-fired combined cycle power plant subjected to a pre-combustion CO2 capture method has been analysed under different design conditions and different heat integration options. The power plant configuration includes the chemical looping reforming (CLR) of natural gas (NG), water gas shift (WGS) process, CO2 capture and compression, and a hydrogen fuelled combined cycle to produce power. The process is denoted as a CLR-CC process. One of the main parameters that affects the performance of the process is the pressure for the CLR. The process is analysed at different design pressures for the CLR, i.e., 5, 10, 15, 18, 25 and 30 bar. It is observed that the net electrical efficiency increases with an increase in the design pressure in the CLR. Secondly, the type of steam generated from the cooling of process streams also effects the net electrical efficiency of the process. Out of the five different cases including the base case presented in this study, it is observed that the net electrical efficiency of CLR-CCs can be improved to 46.5% (lower heating value of NG basis) by producing high-pressure steam through heat recovery from the pre-combustion process streams and sending it to the Heat Recovery Steam Generator in the power plant.

Coefficient determination of reaction rate equations over SCR catalyst used for deNOx system of natural gas-fired gas turbine combined cycle power plants

Coefficient determination of reaction rate equations over SCR catalyst used for deNOx system of natural gas-fired gas turbine combined cycle power plants

CO2 capture from natural gas combined cycles by CO2 selective membranes

This paper performs a techno-economic analysis of natural gas-fired combined cycle (NGCC) power plants integrated with CO2 selective membranes for post-combustion CO2 capture. The configuration assessed is based on a two-membrane system: a CO2 capture membrane that separates the CO2 for final sequestration and a CO2 recycle membrane that selectively recycles CO2 to the gas turbine compressor inlet in order to increase the CO2 concentration in the gas turbine flue gas. Three different membrane technologies with different permeability and selectivity have been investigated. The mass and energy balances are calculated by integrating a power plant model, a membrane model and a CO2 purification unit model. An economic model is then used to estimate the cost of electricity and of CO2 avoided. A sensitivity analysis on the main process parameters and economic assumptions is also performed. It was found that a combination of a high permeability membrane with moderate selectivity as a recycle membrane and a very high selectivity membrane with high permeability used for the capture membrane resulted in the lowest CO2 avoided cost of 75US$/tCO2. This plant features a feed pressure of 1.5bar and a permeate pressure of 0.2bar for the capture membrane. This result suggests that membrane systems can be competitive for CO2 capture from NGCC power plants when compared with MEA absorption. However, to achieve significant advantages with respect to benchmark MEA capture, better membrane permeability and lower costs are needed with respect to the state of the art technology. In addition, due to the selective recycle, the gas turbine operates with a working fluid highly enriched with CO2. This requires redesigning gas turbine components, which may represent a major challenge for commercial deployment.

The improved distribution method of negentropy and performance evaluation of CCPPs based on the structure theory of thermoeconomics

In order to evaluate the performance of components in the large gas-fired combined cycle power plant (CCPP), an improved thermoeconomic analysis method based on the structure theory of thermoeconomics is proposed. First, the fuel-product model is established; the productive structure and the distribution method of negentropy are modified. Negentropy produced and consumed in the gas turbine cycle is also considered. It is proved that the method is reasonable and practical. The exergy cost by the method is higher than that by the traditional method. Then, thermoeconomic model based on structure theory is built by using the improved distribution method of negentropy. Compared with matrix model of thermoeconomics, the accuracy and the effectiveness of the model are verified. The relative error is less than 3%, which is within the permissible range of engineering. Afterwards, relative cost difference and exergoeconomic factor are calculated. The improved relative cost difference is put forward through introduction of non-energy weighting factor. The results indicate that the heat recovery steam generator (HRSG) has a very great potential improvement. The investment on the steam turbine (ST) and the irreversibility of the combustion chamber (CC) should also be paid more attention, the decrease of which makes a great contribution to the decrease of thermoeconomic cost. It shows that the new evaluation index for components of CCPP is reasonable and will support the researches on thermoeconomic optimization of CCPPs.

Non-precious metal (pre-)commercial catalysts for Pd membrane water gas shift

Development of membrane-reactors for use in pre-combustion CO2 capture power schemes is of great interest. The local environment of the catalysts at the catalytic membrane reactor (CMR) conditions is different from conventional applications, inducing changes in demands to the catalyst properties. Here, the use of low-cost base metal catalysts in membrane assisted-water gas shift (MWGS) reaction is studied. A conventional high temperature FeCr-based shift catalyst was studied in a membrane reactor with feed gas mimicking combined-cycle power plant process gas. Combining the catalyst with hydrogen selective Pd membranes, results in approximately 95% hydrogen recovery and CO conversion. No loss of selectivity (through methanation and Fisher–Tropsch reaction) and stability was found during tests, according to expectations, i.e steam/H2 > 0.5 and steam/CO > 2. However, in order to meet these conditions in an ATR + pre-shift based natural gas combined cycle (NGCC) process, steam injection is required at the cost of an efficiency penalty and higher membrane surface area. Using severe conditions representing coal-gasification (IGCC) conditions with high CO concentration and steam/CO < 2, higher hydrocarbons and oxygenates are indeed being formed and catalyst deactivation is unavoidable. For both coal and gas-fired combined-cycle power plants, an alternative catalyst (Topsøe ZnO/ZnAl2O4 type catalyst) was identified with similar hydrogen recovery and activity but superior selectivity and stability to the FeCr type catalyst at steam/H2 < 0.5 and steam/CO < 1.

Performance of polyethyleneimine–silica adsorbent for post-combustion CO2 capture in a bubbling fluidized bed

The high performance of polyethyleneimine (PEI)-based solid adsorbent for CO2 capture has been well recognized in thermogravimetric analysis (TGA) and small-scale fixed bed reactors through the measurements of their equilibrium capacities but has not been really demonstrated on larger scales towards practical utilization. In the present study, a laboratory-scale bubbling fluidized bed reactor loaded with a few kg adsorbent is used to evaluate the adsorption performance of PEI–silica adsorbent under different working conditions including with/without the presence of moisture, different gas–solid contact times, initial bed temperatures, and CO2 partial pressures. The adsorption capacities have shown a clear degradation tendency under dry condition. However, they can be stabilized at a high level of 10.6–11.1% w/w over 60 cycles if moisture (ca. 8.8 vol%) is present in the gas flow during adsorption and desorption. Breakthrough capacities can be stabilized at the level of 7.6–8.2% w/w with the gas–solid contact time of 13 s. The adsorption capacities for the simulated flue gases containing 5% CO2 are only slightly lower than those for the simulated flue gases containing 15% CO2, indicating that the PEI–silica adsorbent is suitable for CO2 capture from flue gases of both coal-fired and natural gas-fired combined cycle power plants. The exothermal heat of adsorption is estimated by the energy balance in the fluidized bed reactor and found to be close (within 10%) to the measured value by TG-DSC. The regeneration heat for the as-prepared PEI–silica adsorbent is found to be 2360 kJ/kgCO2 assuming 75% recovery of sensible heat which is well below the values of 3900–4500 kJ/kgCO2 for a typical MEA scrubbing process with 90% recovery of sensible heat.

Post-combustion CO2 Capture from Natural Gas Combined Cycles by Solvent Supported Membranes

Among the CO2 separation technologies, CO2 membranes are currently receiving an increasing interest, largely thanks to the development of solvents such as ionic liquids and deep eutectic solvents, which are suitable for use in solvent supported membrane systems. The aim of this work is to perform a techno-economic analysis of a natural gas-fired combined cycle power plant integrating CO2 membranes. Such a configuration is based on a two-membrane system, the first one separating the CO2 for final sequestration, the second one used to generate a selective CO2-rich flue gas recycle. The techno-economic assessment uses three modelling tools: (i) process modelling of the complete power plant, performed with the in-house GS code and Aspen Plus, (ii) modelling of the membrane, performed with a finite difference method implemented in Matlab and (iii) economic modelling by a bottom-up approach. The final material balances show that using a moderate pressurization of the combined cycle flue gas results in the lowest energy loss and lowest capture cost.