Natural Gas-fired Combined Cycle 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.

The prospects of flexible natural gas-fired CCGT within a green taxonomy

Despite increased commitments toward net zero, there will likely be a continued need for natural gas to provide low carbon dispatchable power and blue hydrogen to balance the increased penetration of renewables. We evaluate the CO2 emissions intensity of electricity produced by (i)natural gas-fired combined cycle gas turbine (CCGT) power plants with carbon capture and storage (CCS), and (ii) blue hydrogen CCGT plants which uses steam methane reforming with CCS to supply H2. This study aims to determine whether these assets are able to meet a possible green taxonomy emissions threshold of 100kg CO2 eq/MWh. Key considerations include methane leakage, CO2 capture rate, and the impacts of start-up and shut down cycles performed by the CCGT-CCS plant. This study suggests that, in order for natural gas to play an enduring role in the transition toward net zero, managing GHG emissions from both the upstream natural gas supply chain and the conversion facility is key.

Feasibility Study of Scheme and Regenerator Parameters for Trinary Power Cycles

Natural gas-fired combined cycle plants are nowadays one of the most efficient and environmentally friendly energy complexes. High energy efficiency and low specific emissions are achieved primarily due to the high average integral temperature of heat supply in the Brayton–Rankine cycle. In this case, the main sources of energy losses are heat losses in the condenser of the steam turbine plant and heat losses with the exhaust gases of the waste heat boiler. This work is related to the analysis of the thermodynamic and economic effects in the transition from binary to trinary cycles, in which, in addition to the gas and steam–water cycles, there is an additional cycle with a low-boiling coolant. A method for the feasibility study of a waste heat recovery unit for trinary plants is proposed. The schematic and design solutions described will ensure the increased energy and economic performance of combined cycle power plants. Based on the results of the thermodynamic optimization of the structure and parameters of thermal schemes, it was found that the use of the organic Rankine cycle with R236ea freon for the utilization of the low-grade heat of a trinary plant’s exhaust gases operating from a GTE-160 gas turbine makes it possible to achieve a net electrical efficiency of 51.3%, which is a 0.4% higher efficiency for a double-circuit combined cycle gas turbine plant and a 2.1% higher efficiency for a single-circuit cycle with similar initial parameters. On the basis of the conducted feasibility study, the parameters and characteristics of the heat exchangers of the regenerative system of the waste heat recovery unit are substantiated. The use of plain fin-and-tube heat exchangers in the regenerative system of the utilization cycle is the most promising solution. It was found that the level of allowable pressure loss in the regenerator of 10 kPa and the degree of regeneration of 80% allow for maximum economic efficiency of the waste heat recovery unit.

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.

A multi-stage stochastic programming model for the unit commitment of conventional and virtual power plants bidding in the day-ahead and ancillary services markets

As more uncontrollable renewable energy sources are present in the power generation portfolio, the need of more detailed and reliable tools for the optimal operation of energy systems has increased in the last years. This work presents a multi-stage stochastic Mixed Integer Linear Program with binary recourse for optimizing the day-ahead unit commitment of power plants and virtual power plants operating in the day-ahead and ancillary services markets. Scenarios reproduce the uncertainty of the ancillary services market requests, and production of photovoltaic panels. A novel decomposition algorithm is proposed to tackle the challenging multistage stochastic program. The methodology is tested on three types of large power plants: a natural gas-fired combined cycle, a combined heat and power combined cycle with thermal storage, and a virtual power plant integrating a combined cycle with battery and photovoltaic fields. Compared to the typical deterministic unit commitment approach, the proposed stochastic optimization approach allows to increase the revenues of the conventional power plant up to 13.58% and, for the combined heat and power and virtual power plant case, it allows finding a feasible and efficient operational scheduling.

Reserve provision of combined-cycle unit in joint day-ahead energy and reserve markets

With the continuous development of natural gas-fired combined cycle power generation technology, the combined cycle (CC) unit's installed capacity is gradually increasing in the power system because of its flexible operation characteristics. Participating in the energy and reserve markets and taking advantage of flexible mode transfer characteristics, the CC unit can provide the system with energy and sufficient reserve capacity. This paper proposes a bi-level strategic bidding model to study the CC unit’s bidding behavior in the day-ahead energy and reserve markets. The upper-level model is an optimal bidding model for the configuration-based CC unit aiming to maximize its profit. The lower-level model is the joint market clearing model of the energy and reserve markets managed by the independent system operator (ISO). CC unit and ISO in this model influence each other by the locational marginal electricity prices (LMEP) and the locational marginal reserve prices (LMRP) obtained from the lower-level market-clearing model. The CC unit submits the bids to the ISO and arranges the generation plan according to the market clearing results of the lower-level market-clearing model carried out by the ISO. The proposed bi-level optimization model is transformed into a mathematical equilibrium constraint (MPEC) problem by Karush-Kuhn-Tucker (KKT) conditions and duality theory. In this paper, the improved IEEE-6 bus and IEEE-57 bus systems are used as case studies to verify the effectiveness of the proposed bidding strategy for the CC unit. The results show that the proposed bidding strategy can effectively improve the profits of the CC unit in the electricity market. Compared with the case of the CC unit only participating in the energy market, the profits of the CC unit in the market increased by 8.84% and 12.3%.

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.

Exergy Analysis of a Natural Gas-Fired Gas Turbine Combined Cycle Power Plant with Post-Combustion Carbon Capture

Post-combustion carbon capture (PCC) plays an important role in reducing the greenhouse gas emissions. In the present study, an exergy analysis is conducted to assess the exergy destruction and exergetic efficiency of a natural gas-fired combined cycle gas turbine (CCGT) system coupled with the PCC unit. The overall exergetic performance of the system is compared against the baseline CCGT by using realistic data. The working temperature and composition of the exhaust flue gas are two critical parameters that have significant impact on the performance of the absorption liquid and equipment operation. Results show that the highest exergy destruction occurs in the combustion chamber and condenser are 15.69 MW and 11.78 MW, occupying more than 45 % of the exergy destruction of the overall system for the conventional CCGT system. For the CCGT system with PCC unit, the exergy destruction of absorber is relatively high with an exergetic efficiency of 56.18 %. The highest exergetic efficiency is found in the units of combustion chamber and heat recovery steam generator (HRSG), which are 90.23 % and 87.01 %, while the condenser has the lowest efficiency. Identification of the low efficiency component presents an opportunity for improvement of the system.

Front End Engineering Design Study for Carbon Capture at a Natural Gas Combined Cycle Power Plant in California

The Electric Power Research Institute (EPRI), California Resources Corporation (CRC), and Fluor Corporation are conducting a Front-End Engineering Design (FEED) study to determine the technical and economic feasibility of a retrofit, post-combustion, carbon capture technology on a commercially operating, natural gas-fired, combined cycle (NGCC) power plant in California. Fluor’s Econamine FG PlusSM (EFG+) process is being designed to capture CO2 from the flue gas produced by CRC’s 550 MWe Elk Hills Power Plant (EHPP), a NGCC unit located in the Elk Hills Oil Field near Tupman, Kern County, California. The design basis is to route about 79% of the flue to Fluor’s EFG+ plant with the remaining 21% vented as normal through the stack. Steam is supplied to the capture plant from a gas-fired package boiler whose flue gas is combined with the EHPP flue gas as it’s routed to the EFG+ process. The EFG+ process then captures 90% of the total combined inlet CO2. Overall, about 4,000 tonne (t) CO2/day will be captured and delivered at 97+ mol% purity and 160 bar pressure for use by CRC for CO2 enhanced oil recovery (EOR) or CO2 storage in nearby reservoirs. CRC is one of the largest oil producers in California (132,000 barrels oil equivalent/day) and is pursuing CO2-EOR to increase oil output from California’s Elk Hills field. EHPP is unique in that CRC owns and operates the NGCC power plant, provides its natural gas fuel supply, uses much of its steam and electrical output, and will use the captured CO2 for either CO2 enhanced oil recovery or CO2 storage. The regulatory and tax incentives at the California State level and at the U.S. Federal level combined with the use of CO2 for enhanced oil recovery by CRC, provide a significant commercial interest in using the captured CO2 for enhanced oil recovery in California’s Elk Hills region. Permitting work around CCS with EOR in Elk Hills was initiated in 2010, including an expansive Monitoring, Reporting and Verification (MRV) plan. Regulatory outreach and execution for the current CCS-EOR project were initiated in early 2018 via direct engagement with multiple state and federal agencies. Assuming the FEED study results are favourable, this project could lead to deployment of one of the world’s largest carbon capture processes on a power plant – coal- or gas-fired.

An Analysis of the Prospects for Coal-Fired Thermal Power Station Reconstruction on the Basis of Coal Gasification and a Combined-Cycle Unit

Modern trends in technical reequipment of coal-fired thermal power stations (TPS) are analyzed by the example of the Verkhnetagil’skaya District Power Station (GRES), where obsolete coal-fired power units requiring replacement were in operation. This problem is specific for many Russian thermal power stations. Two alternatives of reequipment are considered: replacement of obsolete steam-turbine power units with a natural gas-fired combined cycle unit (CCU) and conversion of coal-fired power units into integrated gasification combined-cycle units (IGCCU) with gas turbines operating on purified synthesis gas. Technical reequipment of the considered TPS was performed by replacing the coal-fired steam-turbine power units of phase I–II with a 420 MW CCU. The CCU core was a 288 MW Siemens SGT5-4000F gas turbine. A CCU on its basis was modelled in the THERMOFLEX code. The calculated results demonstrated high power and environmental effectiveness in replacement of coal-fired power units at TPSs with natural gas-fired CCUs, thereby cutting down coal equivalent consumption by 727 000 t.c.e. (or 24%). For conversion of a TPS to an IGCCU, the fuel saving could be as great as 543 000 t.c.e./year (18%) under comparable conditions. In this case, the atmospheric emissions (of dust and SO2) could be decreased many times (by 99%) due to implementation of an effective gas treatment process in the gasification system. Due to the huge coal reserves in Russia, the conversion of coal-fired TPSs to modern technologies with coal gasification may be a promising alternative for many TPSs during their reconstruction. In addition, it will contribute to improving the country’s energy security. In addition, this will improve the country’s energy security.

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

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.

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.

ION 6-Month Campaign at TCM with its Low-Aqueous Capture Solvent Removing CO2 from Natural Gas Fired and Residue Fluid Catalytic Cracker Flue Gases

ION Engineering’s (ION) advanced solvent is one of the leading second-generation solvent systems currently under development for post-combustion carbon dioxide (CO2) capture. This paper discusses the results obtained at CO2 Technology Centre Mongstad (TCM) in Mongstad, Norway between September 2016 and April 2017, where ION captured over 14,800 tonnes of CO2 throughout the 2,775-hour testing campaign. The testing was done on flue gases from a natural gas-fired combined cycle heat and power facility (CHP) and a residue fluid catalytic cracker (RFCC) from the adjacent Statoil refinery at a scale comparable to 12 MWe. The CO2 concentrations in both flue gas types could be varied using recycle from the stripper or dilution by air. In this work, CO2 concentration settings of between 3.6% and 15.0% were tested. In the TCM plant, which is not optimized for ION’s solvent system, ION achieved a specific reboiler duty (SRD) as low as 3.2 MJ/kg CO2 during the testing at TCM while demonstrating 90% capture efficiency with low emissions and low corrosion. Furthermore, testing showed capturing 98% of the CO2 with ION’s solvent results in only a 10% increase in energy consumption. The results from ION’s campaign at TCM were then used to validate the ION process model in ProTreat® to high accuracy. Subsequent process design optimization shows ION’s solvent is capable of an SRD of less than 2.5 MJ/kg CO2 when incorporating ION’s key process operations. Throughout pilot testing, ION has confirmed its understanding of process improvements and analytics that will enable successful operation of its solvent system at significantly lower L/G circulation rates, packing heights, and regeneration energies than baseline mono-ethanolamine. ION anticipates that the recently completed demonstration at TCM, along with future projects, will facilitate further advancements in the field of CO2 capture and deployment of ION’s technology.

Natural Gas Combined Cycle Utilization: An Empirical Analysis of the Impact of Environmental Policies and Prices

Recent climate regulations include increased utilization of natural gas-fired combined cycle (NGCC) generators as a means for offsetting coal generation to reduce carbon emissions. There have been substantial increases in utilization for some generators, but most remain below baseload levels. This paper examines the factors that have driven NGCC utilization from 2003-2014. I run difference-in-dif-ference models to evaluate the relationships between environmental policies and natural gas prices on NGCC utilization. Both low natural gas prices and the Clean Air Interstate Rule (CAIR) drive increases in utilization. However, the size of the impact by CAIR depends on the age of the plant. I use the estimates from this model for a counterfactual analysis which reveals CAIR had nearly twice the impact of low natural gas prices on increased utilization in nationwide averages.

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%).