Fixed and Capture Level Reduction operating modes for carbon dioxide removal in a Natural Gas Combined Cycle power plant

Advanced bibliometric analysis on the development of natural gas combined cycle power plant with CO2 capture and storage technology

Techno-economic evaluation of the 2-amino-2-methyl-1-propanol (AMP) process for CO2 capture from natural gas combined cycle power plant

The strategic technology options for mitigating CO 2 emissions in power sector: assessment of Shanghai electricity-generating system

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

This study investigates the crucial role of Carbon Capture and Storage (CCS) technology in mitigating CO2 emissions from Poland’s power systems, which is essential not only for meeting climate targets but also for maintaining energy security in the country. Acknowledging natural gas as a transitional fuel, the focus is on evaluating the decarbonization potential of the natural gas combined cycle (NGCC) power plant. The NGCC with and without an amine-based carbon capture unit was modeled using IPSEpro (SimTech, version 7.0). It was found that the annual CO2 emission from 435.68 MWe (net) NGCC can be reduced from 1,365,501 tons (357.8 kgCO2/MWh) to 136,556 tons (42.9 kgCO2/MWh). On the other hand, the CCS reduced the net electric power of the NGCC from 435.68 MW to 363.47 MW and the net energy efficiency from 55.60% to 46.39%. Nonetheless, these results demonstrate the potential of using the amine-based CO2 capture technology in NGCC systems. This is especially important in the context of the decarbonization of the Polish power system.

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.

Amino-2-methyl-1-propanol-based Post-combustion Capture Process with Solvent Storage for Decarbonisation of Natural Gas Combined Cycle Power Plant

Study on the configuration of bottom cycle in natural gas combined cycle power plants integrated with oxy-fuel combustion

Economic comparison between coal-fired and liquefied natural gas combined cycle power plants considering carbon tax: Korean case

This paper examines the cost of CO(2) capture and storage (CCS) for natural gas combined cycle (NGCC) power plants. Existing studies employ a broad range of assumptions and lack a consistent costing method. This study takes a more systematic approach to analyze plants with an amine-based postcombustion CCS system with 90% CO(2) capture. We employ sensitivity analyses together with a probabilistic analysis to quantify costs for plants with and without CCS under uncertainty or variability in key parameters. Results for new baseload plants indicate a likely increase in levelized cost of electricity (LCOE) of $20-32/MWh (constant 2007$) or $22-40/MWh in current dollars. A risk premium for plants with CCS increases these ranges to $23-39/MWh and $25-46/MWh, respectively. Based on current cost estimates, our analysis further shows that a policy to encourage CCS at new NGCC plants via an emission tax or carbon price requires (at 95% confidence) a price of at least $125/t CO(2) to ensure NGCC-CCS is cheaper than a plant without CCS. Higher costs are found for nonbaseload plants and CCS retrofits.

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 %.

Heat integration of natural gas combined cycle power plant integrated with post-combustion CO2 capture and compression

Optimal operation of MEA-based post-combustion carbon capture for natural gas combined cycle power plants under different market conditions

Natural gas is an important source of energy. This article addresses the problem of integrating an existing natural gas combined cycle (NGCC) power plant with a carbon capture process using various solvents. The power plant and capture process have mutual interactions in terms of the flue gas flow rate and composition vs. the extracted steam required for solvent regeneration. Therefore, evaluating solvent performance at a single (nominal) operating point is not indicative and solvent performance should be considered subject to the overall process operability and over a wide range of operating conditions. In the present research, a novel optimization framework was developed in which design and operation of the capture process are optimized simultaneously and their interactions with the upstream power plant are fully captured. The developed framework was applied for solvent comparison which demonstrated that GCCmax, a newly developed solvent, features superior performances compared to the monoethanolamine baseline solvent. © 2015 American Institute of Chemical Engineers AIChE J, 62: 166–179, 2016

Application of optimal design methodologies in retrofitting natural gas combined cycle power plants with CO2 capture