Gasification Combined Cycle Power Plant Research Articles

Impact of energy integration on post-combustion CO2 capture: A comparative analysis of chemical absorption and calcium looping technologies in coal-fired and natural gas combined cycle power plants

Chemical absorption (Che) and calcium looping (CaL) have been recognized as the promising technologies for post-combustion CO2 capture (PCC) applied in fossil fuel power plants. However, there is a lack of understanding of how the energy integration affects the performance difference of the two separation technologies employed for the retrofitted coal-fired (CFPP) and natural gas combined cycle (NGCC) power plants. Thus, this study aims to provide a new perspective by investigating power generation fuel and heating fuel from energy conversion and transfer pathways. Results indicate that in the case of CFPP-PCCs, adopting the CaL technology can enhance the initial parameters of the steam cycle and reduce the heat transfer temperature difference for the utilization of heating fuel, where the heat transfer exergy destruction of heating fuel drops from 27.9 % to 15.1 % compared to the Che capture system. Conversely, for NGCC-PCCs, due to the superior performance of the combined cycle, the adoption of the CaL technology undermines the advantages of the heat transfer and power generation units, resulting in inferior performance compared to the Che capture system in most conditions. Results implicate that the degree of difference in energy conversion and transfer pathways between the power generation fuel and the heat supply fuel directly determines the performance of the capture system. Thus, concentration CO2 along with the efficient fuel conversion will be a promising direction for the innovation of capture technologies.

CO2-selective membrane reactor process for water-gas-shift reaction with CO2 capture in a coal-based IGCC power plant

Integrated gasification combined cycle (IGCC) power plants enable pre-combustion carbon capture to reduce CO2 emissions. Membrane water-gas-shift (WGS) reactors can intensify these processes by converting raw syngas to H2 with simultaneous CO2 capture in one unit. This paper reports process design and techno-economic analysis (TEA) for a membrane reactor (MR) process with a CO2 selective ceramic-carbonate dual-phase (CCDP) membrane for WGS reaction with CO2 capture for a IGCC power plant. The target performance includes CO conversion > 95 %, hydrogen purity > 90 %, CO2 purity > 95 %, and carbon capture > 90 %. Using a commercial catalyst and a CCDP membrane, the MR can achieve the performance target at 750 °C and space velocity of 250 h−1. The outcome of the process design and TEA shows that the CCDP MR has an operating cost of $24 M/year, significantly lower than that for the conventional processes (40 M$/year). However, the MR process has a higher capital cost ($1007 M) than the conventional process ($527 M) because of the higher cost of the CCDP MRs. Modeling analysis shows a MR with higher CO2 permeance can deliver the target at a higher space velocity and lower membrane surface area to catalyst volume ratio, leading to a significantly reduced MR capital costs.

Assessing Carbon Capture and Carbonation in Recycled Concrete Aggregates: A Holistic Life Cycle Assessment Perspective with Simulation at Industrial Scale

This work explores a life cycle assessment (LCA) concerning carbon capture and carbonation of recycled concrete aggregates (RCA), addressing the growing challenges posed by increased carbon emissions in power generation and ecological concerns tied to construction waste. We propose an integrated solution involving the capture of low-concentration carbon dioxide (CO2) from natural gas combined cycle (NGCC) power plants through aqueous ammonia absorption and sequestration by mineralization of RCA. The cradle-to-gate LCA focuses on an industrial-scale scenario for capturing 200 kilotonnes of CO2 annually, with functional unit per tonne of carbonated RCA output. The findings reveal a net positive carbon abatement of 21.42 kg CO2 eq., with heat production and electricity consumption being the major contributors to global warming potential (GWP). Within the spectrum of environmental impact categories under study, Marine Aquatic Ecotoxicity Potential (MAETP) exhibits a significant impact, primarily influenced by sulfur production. Human Toxicity Potential (HTP) follows as the second-worst contributor, with 96.80% of its impact attributed to heat and sulfur production. Subsequently, Acidification Potential (AP) follows, arising from sulfur and sulfuric acid production. Sensitivity analysis and Monte Carlo simulation introduce a ±20% standard deviation to electricity and thermal energy consumption. Scenario analysis demonstrates a net carbon-positive abatement potential of 286.66 kg CO2 eq. per tonne of CO2 input. Employing carbon mineralization for CO2 capture not only reduces emissions but also repurposes waste materials, providing a comprehensive and sustainable solution for effective CO2 management, contributing to reduced sand mining, and offering cost advantages through the production of carbonated RCA.

Evaluating a computerized CCS model against current technologies to optimize environmental conservation for the Patuakhali power plant in Bangladesh

Bangladesh's burgeoning focus on power generation has prompted the government to implement ambitious plans to install power plants. Among these developments is the impending operation of a 2∗660 MW coal-power station in Patuakhali, which will operate at the end of the month in December 2024. The proposed technology addresses concerns about CO2 emissions from a plant, potentially causing health issues and threatening plant biodiversity, but may present challenges compared to other technologies. Monoethanolamine (MEA), eutectic, and potassium taurate are potential solvents for CO2 capture in coal power plants due to their power absorption rate, capacity, and resilience to oxidative as well as thermal degradation. However, the significant challenges include corrosiveness, solvent loss, and high energy demand. By contrast, advanced research includes fixed and capture level reduction operating modes for carbon dioxide removal in natural gas combined cycle power plants, which is appropriate for use in natural gas combined cycle (NGCC) power plants where further research is needed for coal-fired power plants. The current generation of CO2 removal equipment, such as electrostatic precipitators (ESP) and flue gas desulphurization units (FGD), can remove CO2 at 99 % and 80 %–99 %, respectively. These devices have several serious drawbacks, including high water consumption, high costs, complex waste management, and operational errors. Additionally, equipment must be modified to increase efficiency and maximize heat rate. Notably, the moisture content in coal must be reduced from 0.6 to 5.9 %, heat must be recycled from 1.2 to 3.6 %, the steam turbine loop must be improved from 2 to 4.5 %, and advanced controls and sensors must be replaced or used up to 1.5 times.Our study, utilizing an established operational model sanctioned within the country and assessment, revealed an approximate daily carbon emission of 4.806 million kilograms from the power plant. Employing the Sundarbans' sequestration rate, we calculated a carbon tolerance level of around 4.2 million kilograms daily for the plant area. This study also highlights the potential of computerized carbon capture and storage (CCCS) technology to significantly reduce emissions in the Sundarbans, which have nearly zero levels. It compares a computerized CCS model with an existing model, estimating over 90 % reduction considering 10 % mechanical faults. Implementing a computerized system can reduce CO2 leaks, risks, operational efficiency, costs, and policy compliance. It ensures the security of carbon capture, transportation, and storage processes, balancing environmental preservation and economic development. Advanced technologies can reduce emissions to zero, and the captured carbon can be used for petroleum-enhanced oil recovery techniques, which are briefly described. It also offers economic benefits and carbon credits, improving air quality and ocean health by mitigating pollutants and CO2 emissions.

Energy consumption optimization of CO2 capture and compression in natural gas combined cycle power plant through configuration modification and process integration

Currently, natural gas combined cycle (NGCC) power plants account for a quarter of global electricity power supply and lead to greenhouse gas emissions. Carbon capture and storage (CCS) is one of the most effective technologies to reduce carbon emissions in the short term. However, the monoethanolamine (MEA)-based CO2 absorption and compression process is energy-intensive, which significantly reduces the power generation efficiency of NGCC. In addition, the waste hot and cold energy from NGCC and liquefied natural gas (LNG) regasification process, which are generally wasted, can be recovered for the CCS process. Therefore, this study aims to reduce the energy consumption of the carbon capture process and recover waste LNG cold energy and hot energy in the NGCC through configuration modification and process integration. The results show that the energy consumption of CO2 regeneration in the proposed CO2 capture process configuration is reduced by 18.03 %, and the net power efficiency of the NGCC plant increases from 48.88 % to 50.10 %. Furthermore, a cascade two-stage organic Rankine cycle is integrated into the system for waste heat recovery, which can generate 5.04 MW electric power and reduce the efficiency penalty of the plant from 13.72 % to 10.29 %. By contrast, the alternative application of LNG cold energy to the CO2 compression process reduces compression power by 3.95 MW with a lower footprint and utility requirement while the efficiency penalty is decreased by 3.15 %.

Assessment of the Use of Carbon Capture and Storage Technology to Reduce CO2 Emissions from a Natural Gas Combined Cycle Power Plant in a Polish Context

Assessment of the Use of Carbon Capture and Storage Technology to Reduce CO2 Emissions from a Natural Gas Combined Cycle Power Plant in a Polish Context

Assessment of Economic Viability of Conversion of Open Cycle to Combined Cycle Gas Power Plant

The paper identified the types of gas turbines available in the electric power generating system in Nigeria and assessed the economic viability of converting open cycle to combined cycle gas power plants in order to maximize the electricity generation output without further gaseous fuel consumption in the existing thermal plants in the country. Data were obtained through primary and secondary sources on all the operational power plants in Nigeria. These data were analyzed using engineering economy methods. The result showed that by using the average generation of each plant for a period of 3 years as a baseline for conversion, an additional 1142.1 MW would be obtained after conversion to combined cycle without increase in gas consumption. In addition, the result showed the NPV values and benefit-cost ratio were greater than zero and one respectively, indicating that the project is economically viable for each conversion process. The sensitivity analysis over a range of values from ±10 to ±30% of the investment cost did not affect the economic viability of the project. Furthermore, the result showed that the cost of generating electricity borne by the society is much lower for a combined cycle than for an open cycle. The study concluded that conversion of the gas turbine from open cycle to combined cycle is economically viable and an additional generation of 1142.1 MW can be obtained without increasing the gas consumption.

Nonlinear state estimation of a power plant superheater by using the extended Kalman filter for differential algebraic equation systems

A nonlinear estimator was developed for process monitoring of a power plant superheater system to estimate the transient temperature profiles of the critical measured and unmeasured variables under load-following operations. The model used in the estimator was a detailed, distributed, first-principles, differential–algebraic equation model. The superheater geometry is characterized based on an operating natural gas combined cycle power plant. The model included mass and energy balances for the operating fluids, i.e., steam and flue gas, with due consideration of tube wall temperature dynamics. The dynamic model was used for state and parameter estimation by using a modified extended Kalman filter. When results are compared with the data from a natural gas power plant, the estimator yielded root mean squared error of 0.2 °C for the main steam temperature compared to 1 °C obtained from the first-principles model. While the first-principles model yielded as high as 2.5 °C absolute instantaneous error for the tube temperatures, the estimator reduced the absolute instantaneous error below 0.3 °C for most variables. Performance of the estimator for estimating critical variables like the main steam temperature and flue gas temperature was evaluated in the presence of high model mismatch and noisy measurement data by simulating load-following operation of the plant. The estimator yielded maximum absolute instantaneous error of 3.4 °C for the flue gas and 1 °C for the main steam temperature.

Proposal and thermodynamic investigation of pressurized calcium looping integrated with chemical looping combustion for tail-end CO2 capture in a retrofitted natural gas combined cycle power plant

The integration of tail-end calcium looping into an existing natural gas combined cycle (NGCC) power plant has minimal impact on CO2 capture retrofits. However, a high volume of flue gas needs to be preheated before entering the carbonator, and the relatively high energy consumption of oxygen production exacerbates the energy penalty of the NGCC system with tail-end CO2 capture. This paper proposes the method of pressurized calcium looping integrated with chemical looping combustion (PCaL-CLC). It employs the PCaL-CLC method to reduce the energy penalty and energy consumption of the NGCC system with tail-end CO2 capture. Results show that the proposed system using the PCaL-CLC method achieves a 3.0% reduction in energy penalty, decreasing from 9.1% in the reference system employing the calcium looping method to 6.1% in the proposed system. Besides, the specific energy consumption for CO2 avoided (SPECCA) declines from 4.43 MJLHV/kg CO2 to 2.76 MJLHV/kg CO2. Exergy analysis and energy utilization diagrams reveal the underlying reason for improving system performance. Furthermore, by optimizing the operating parameters of the gas turbine and equipping it with advanced heat recovery steam generation, an energy penalty of 2.9% and a SPECCA of 1.21 MJLHV/kg CO2 are achieved without CO2 compression, which is superior to those of amine scrubbing and hot-end calcium looping CO2 capture technologies. The proposed PCaL-CLC method offers an alternative approach to reducing the energy consumption of tail-end CO2 capture in existing natural gas combined cycle power plants.

Tracing the carbon capture energy distribution in a natural gas combined cycle power plant under variable operating conditions

A thermodynamic analysis method with a new criterion was introduced to reveal and dynamic track the internal energy consumption distribution of natural gas combined cycle power plants with CO2 capture. The new method decomposes the capture energy consumption into separation energy consumption and system integration energy consumption caused by gas turbines, steam turbines, heat recovery steam generators and steam extraction. The results indicate that load variation has little effect on the energy penalty of the separation process, which accounts for over 50 % of the total capture energy consumption and is stable at around 0.8 MJe/kg CO2 for MEA-based cases, while the integration performance becomes better with load decreasing, since the superior matching between extraction steam and reboiler parameters. Besides, exhaust gas recirculation technology reduces energy consumption caused by steam extraction by around 67 %∼85 % and brings an additional penalty of 0.1–6 MW on the gas turbine under 40–100 % load conditions. Therefore, exploring new absorbents and optimizing the matching between extraction steam and reboiler parameters are the critical points for capture system without exhaust gas recirculation. In contrast, for capture system with exhaust gas recirculation, energy consumption caused by the deterioration performance of gas turbines is crucial under high operation load, while absorbent innovation is dominant at low load. With the aid of the thermodynamic analysis method introduced in this paper, a better understanding of CO2 capture systems under variable load conditions can be obtained, which may be helpful for reducing energy consumption in CO2 capture technologies.

Economic impact of thermal energy storage on natural gas power with carbon capture in future electricity markets

As policies evolve to reflect climate change goals, the use of fossil fuel power plants is expected to change. Many fossil fuel power plants may opt to incorporate carbon capture and storage (CCS) technologies in response to evolving emissions policies. Additionally, fossil plants may need to be operated flexibly to accommodate the growing concentration of renewable energy systems. Unfortunately, most CCS technologies are very expensive, and they impose a parasitic load on the power plant, thereby decreasing net power output and the ability to operate flexibly. This investigation evaluated the economic potential of using hot and cold thermal energy storage (TES) to supplement the peak power output and flexibility of a natural gas combined cycle (NGCC) power plant with CCS capabilities. The two TES subsystems (hot and cold) were charged during periods of relatively low electricity prices and discharged during NGCC operation: resistively heated hot TES to offset the CCS parasitic heat load and vapor compression cooled cold TES to chill the inlet air to the power plant. Thermodynamic models were created for the base NGCC + CCS power plant, the hot TES equipment, and the cold TES equipment, to determine key performance and cost parameters such as net power output, fuel consumption, emissions captured, capital costs, and operational costs. These parameters were then used to simulate the operation of the power plant with and without the TES technologies in accordance with fourteen electricity pricing structures predicted for different future electricity market scenarios. The difference in net present value (NPV) between the base NGCC + CCS power plant and power plant with the TES technologies was used as the primary economic metric in this analysis. The NPV benefit from increased revenue due to TES utilization was found to outweigh the NPV penalty from the additional capital costs. This economic result was attributed to the low cost of the TES equipment and the ability to charge the storages using cheap electricity from high levels of renewable output. The results have shown that hot TES increased NPV in 12 of 14 market scenarios while the cold TES increased NPV in 14 of 14 market scenarios. A combination of both hot and cold TES yielded the largest increases in NPV.

Techno-economic evaluation of CO2 capture and storage retrofit in decarbonizing different thermal power plants: A case study in China

Given that thermal power plants are the dominant mode of power generation in China, decarbonization from thermal power plants is significant to protect the global climate from further warming. CO2 capture and storage (CCS) is one of the most promising approaches for mitigating CO2 emissions; therefore, studies evaluating the effect of CCS retrofit on thermal power plants are urgently required. This study selected coal-fired power plant (CFPP) and natural gas combined cycle power plant (NGCC) as the representative technologies for thermal power plants, and proposed system models for their integrations with CCS. A comprehensive evaluation system was established using different metrics such as specific CO2 emission (CO2 emission per kWh), net electric efficiency, levelized cost of electricity (LCOE), and cost of avoiding CO2 emission (COAE). The detailed effects of fuel price fluctuations, technological advances, and different technology combinations on key metrics were analyzed, in order to propose policy recommendations for the decarbonization of China's thermal power plants using CCS technology. The following results were obtained: (1) The use of CCS to reduce CO2 emissions from thermal power plants will lead to a significant increase in LCOE. Each 100 g/kWh reduction in specific CO2 emission will result in 11 %–14.5 % increase in LCOE for CFPP + CCS, and 9.5 %–13.5 % increase for NGCC + CCS. (2) Technological advances toward reducing specific heat consumption for CO2 capture should be strongly promoted to reduce LCOE. Each 0.4 GJ/t reduction in specific heat consumption will result in an approximately 0.066 CNY/kWh reduction in LCOE for CFPP. (3) Both CFPP + CCS and NGCC + CCS exhibit potential for decreasing COAE below 600 CNY/t, although the technologies to meet this threshold are not currently realistic at higher fuel prices.

Techno-economic analysis on the balance of plant (BOP) equipment due to switching fuel from natural gas to hydrogen in gas turbine power plants

<abstract> <p>The concerns over greenhouse gas emissions, environmental impacts, climate change, and sustainability continue to grow. As a result of countermeasures, many modern gas turbine power plants and combined cycle power plants are considering to use hydrogen as a clean fuel alternative to fossil fuels in the power plant industry. We assessed the implications of such transition from natural gas to hydrogen as fuel in a gas turbine power plant's balance of plant (BOP) equipment. Using the DWSIM process simulation software and the methodology of compression power changes against different gas compositions, the impact of blending hydrogen with natural gas on temperature differentials, energy consumption, adiabatic efficiency, compression power, and economic implications in gas turbine power plants were examined in this paper. We discovered, through analysis, that there was not a noticeable boost in compression power or energy consumption when 50% hydrogen and 50% natural gas were blended. Similarly, there was no discernible difference in temperature differentials or adiabatic efficiency when 30% hydrogen and 70% natural gas were blended. Moreover, mixing 50% hydrogen and 50% natural gas did not result in a noticeable cost climb. In addition, the techno-economic analysis presented in this paper offered valuable insights for power plant engineers, power generation companies, investors in energy sectors, and policymakers, highlighting the nature of the fuel shift and its implications on the economy and technology.</p> </abstract>

Thermodynamic Study on Decarbonization of Combined Cycle Power Plant

Integrating hydrogen firing and a carbon capture plant (CCP) into a natural gas combined cycle (NGCC) power plant is a promising strategy for reducing CO2. In this study, process simulation in Aspen PLUS of hydrogen co-firing in a 40 MW turbine gas combined cycle power plant was done at an identical gas turbine inlet temperature from 0%.cal to 30%.cal. The evaluated cases were hydrogen co-firing with CCP (H2 Co-firing + CCP) and hydrogen co-firing without CCP (H2 Co-firing). The results showed a 6% CO2 emission reduction per 5% increase in hydrogen, albeit with increased NOx emissions. H2 Co-firing experienced a decrease in net power with rising hydrogen co-firing, while H2 Co-firing + CCP saw an increase but remained below Case 2 due to the energy penalty from the carbon capture plant. The capital cost of H2 Co-firing + CCP exceeds that of H2 Co-firing due to CCP usage, impacting gross revenue. The sensitivity analysis indicated that the cost of hydrogen has higher sensitivity compared to the cost of CCP. Lowering hydrogen prices is recommended to effectively reduce CO2 emissions in NGCC.

Combined pinch and exergy analysis for post-combustion carbon capture NGCC integrated with absorption heat transformer and flash evaporator

Natural gas combined cycle power plant (NGCC) with post-combustion carbon capture (PCC) is a transitional technology for achieving net-zero emissions, but PCC significantly decreased its energy efficiency. In the work, absorption heat transformer and flash evaporator (AHT-FE-aided system) was used to mitigate the energy penalty of NGCC caused by PCC. Subsequently, heat exchange networks (HENs) were constructed for the system, followed by a combined pinch and exergy analysis (CPEA). The results showed that the improved HEN of the NGCC with AHT-FE-aided PCC (proposed system) resulted in 13.4 % less exergy destruction than the NGCC with PCC (reference system). To fully understand the exergy destruction and environmental impact of this system, an exergy distribution analysis and a technical evaluation were conducted. The net energy and exergy efficiency of the proposed system (48.11 %/46.04 %) were 1.73 % and 1.65 % higher than the reference system (46.38 %/44.39 %) respectively. The energy penalty of PCC in the proposed system (8.76 %) was lower than the reference system (11.89 %). In addition, the proposed system decreased fuel consumption by 5.90 g NG/kWh. This study confirms that the AHT-FE-aided system reduces the energy penalty of NGCC caused by PCC, and that CPEA is an effective tool to guide improvements in this area.

Cost optimization methodology based on carbon-techno-economic analysis: An application to post-combustion carbon capture process

Recently, a carbon tax has been introduced to encourage emissions reduction, and it has become an additional cost burden. To evaluate the carbon emissions and process costs simultaneously in a single indicator, a carbon-techno-economic analysis (CTEA) methodology that combines carbon tax and process cost was developed in this study. The proposed CTEA model was used to optimize the post-combustion carbon capture (PCC) process, which is an energy- and cost-intensive process. In CTEA optimization, as the carbon tax price increases from $12.5/tonne CO2 to $250/tonne CO2, more energy is provided to the PCC process to increase the carbon capture level from 58.92 % to 99.64 %. This results in a decrease in power generation of the natural gas combined cycle power plant from 462.33 MW to 436.07 MW, and an increase in the incremental cost of electricity from $14.05/MWh to $17.74/MWh. The decrease in profit from CTEA optimization is only 8.75 %, which is relatively smaller than the 11.68 % and 32.32 % decrease in profit from energy and TEA optimization, respectively. The results demonstrate that CTEA-based process optimization is beneficial and highlight the trade-off relationship among carbon tax, process cost, and profit. The results of this study can guide commercial companies in setting operational strategies for their processes as carbon tax prices change and can also assist governments in establishing carbon tax policies to encourage carbon emission reductions in industries.

Flexible carbon capture using MOF fixed bed adsorbers at an NGCC plant

Novel carbon capture systems are necessary to help natural gas power plants approach net zero CO2 emissions. We propose a hybrid carbon capture system attached to a natural gas combined cycle (NGCC) power plant that consists of a membrane system and a solid sorbent system, with this work focusing on the design of the solid sorbent system. We modeled fixed bed adsorbers that are packed with metal-organic framework (MOF) solid sorbents that adsorb CO2 and undergo temperature swing desorption using steam from the power plant. Parametric simulation of adsorber conditions showed that ten 5-m diameter beds adsorbing in parallel with 4.9 bars inlet gas pressure and 1.5 bars of steam pressure at a flow rate of 0.15 kmol/s led to optimized performance. This study enabled us to determine that the MOF bed adsorber can attain 86.6 % and 85.4 % carbon capture during peak and off-peak operation, respectively. When combined with the membrane capture system, this results in overall capture rates of 98.4 % and 98.9 % during peak and off-peak operation, respectively. Although we were unable to attain net-zero or net-negative emissions in this study, we are confident that net-negative operation could be obtained in future work by selecting a solid sorbent better suited to direct air capture conditions so that more air could be processed by the solid sorbent system.

Design of a Parabolic Trough Collector Solar Field for a Pilot CO2 Capture Plant from Natural Gas Combined Cycle Power Plant Flue Gas.

A parabolic trough collector solar field was designed to supply the heat needed to regenerate the CO2-rich monoethanolamine in a solar-assisted carbon capture system. Process design modeling was performed for 90% of the CO2 removal from 1% of the flue gas produced by a 255 MWe natural gas combined cycle power plant. Calculations with and without 24 h of thermal energy storage by increasing the solar collector size needed and providing a buffer vessel to store hot heat transfer fluid were performed. A dynamic analysis of the solar field using the hourly solar forecast was performed to investigate how heat transfer fluid mass flow changes during January and June to maintain the desired parabolic solar field outlet temperature needed for CO2 reboiler operation. The calculations provided here present an explicit method to calculate relevant solar field design parameters that can be scaled up and used in solar energy-assisted gas capture processes.

Optimization of a Natural Gas Power Plant with Membrane and Solid Sorbent Carbon Capture Systems

Carbon capture & storage (CCS) with high capture rates (90-99%) will be necessary to keep natural gas around in a low-carbon future. Furthermore, as intermittent renewable energy expands, natural gas power plants will have to operate at low-load conditions more frequently. To meet these demands, we propose a natural gas combined cycle (NGCC) power plant with a hybrid CCS system that can attain high capture rates and easily cycle between high-load and low-load conditions. More specifically, we propose an integrated system where natural gas exhaust is first processed by a membrane CCS system and then by a solid sorbent CCS system. We integrated models of an NGCC plant, a membrane carbon capture system and a solid sorbent carbon capture system into a single optimization platform to maximize the net present value (NPV) and carbon capture rate of the integrated system. The optimization results indicate a 99.3% carbon capture rate from the inlet natural gas stream at high-load conditions, and a 99.6% carbon capture rate from the inlet natural gas stream at low-load conditions. Compared to a baseline NGCC system without carbon capture, the integrated system has a higher NPV, which indicates that performing carbon capture is more profitable than operating an NGCC system without carbon capture in a future with CO2 taxes. Compared to a baseline NGCC system with an amine-based CCS system that performs 90.7% carbon capture, the proposed integrated system captures more carbon and emits less CO2, while still maintaining a competitive CO2 capture cost.

Thermal integration of a natural gas combined cycle power plant with carbon capture and utilization technologies

Thermal integration of a natural gas combined cycle power plant with carbon capture and utilization technologies