Part-load analysis of a chemical looping combustion (CLC) combined cycle with CO2 capture

This paper presents part-load evaluation of a natural gas-fired chemical looping combustion (CLC) combined cycle with CO₂ capture. The novel combined cycle employs an air-based gas turbine, a CO₂-turbine and a steam turbine cycle. In this combined cycle, the CLC reactors replace combustion chamber of the gas turbine. The proposed combined cycle has a net plant efficiency of about 52.2% at full-load, including CO₂ compression to 200 bar. The part-load evaluation shows that reducing the load down to 60% results in an efficiency drop of 2.6%-points. However, the plant shows better relative part-load efficiency compared to conventional combined cycles. The pressure in CLC-reduction and -oxidation reactors is balanced by airflow control, using a compressor equipped with variable guide vanes. A combination of control strategies is discussed for plant start-up and shutdown and for part-load when airflow reduction is not practically possible with current generation of compressors. The results show that the combined cycle has a promising efficiency even at part-load; however, it requires an advanced control strategy.     

Techno-economic assessment on the fuel flexibility of a commercial scale combined cycle gas turbine integrated with a CO2 capture plant

Post-combustion carbon capture is a valuable technology, capable of being deployed to meet global CO₂ emissions targets. The technology is mature and can be retrofitted easily with existing carbon emitting energy generation sources, such as natural gas combined cycles. This study investigates the effect of operating a natural gas combined cycle plant coupled with carbon capture and storage while using varying fuel compositions, with a strong focus on the influence of the CO₂ concentration in the fuel. The novelty of this study lies in exploring the technical and economic performance of the integrated system, whilst operating with different fuel compositions. The study reports the design of a natural gas combined cycle gas turbine and CO₂ capture plant (with 30 wt% monoethanolamine), which were modelled using the gCCS process modelling application. The fuel compositions analysed were varied, with focus on the CO₂ content increasing from 1% to 5%, 7.5% and 10%. The operation of the CO₂ capture plant is also investigated with focus on the CO₂ capture efficiency, specific reboiler duty and the flooding point. The economic analysis highlights the effect of the varying fuel compositions on the cost of electricity as well as the cost of CO₂ avoided. The study revealed that increased CO₂ concentrations in the fuel cause a decrease in the efficiency of the natural gas combined cycle gas turbine; however, rising the CO₂ concentration and flowrate of the flue gas improves the operation of the capture plant at the risk of an increase in the flooding velocity in the column. The economic analysis shows a slight increase in cost of electricity for fuels with higher CO₂ contents; however, the results also show a reduction in the cost of CO₂ avoided by larger margins.     

Integration of gas switching combustion in a humid air turbine cycle for flexible power production from solid fuels with near-zero emissions of CO2 and other pollutants

This work presents a novel plant configuration for power production from solid fuels with integrated CO₂ capture. Specifically, the Gas Switching Combustion (GSC) system is integrated with a Humid Air Turbine (HAT) power cycle and a slurry fed entrained flow (GE-Texaco) gasifier or a dry fed (Shell) gasifier with a partial water quench. The primary novelty of the proposed GSC-HAT plant is that the reduction and oxidation reactor stages of the GSC operation can be decoupled allowing for flexible operation, with the oxygen carrier serving as a chemical and thermal energy storage medium. This can allow the air separation unit, gasifier, gas clean-up, CO₂ compressors and downstream CO₂ transport and storage network to be downsized for operation under steady state conditions, while the reactors and the power cycle operate flexibly to follow load. Such cost-effective flexibility will be highly valued in future energy systems with high shares of variable renewable energy. The GSC-HAT plant achieves 42.5% electrical efficiency with 95.0% CO₂ capture rate with the Shell gasifier, and 41.6% efficiency and 99.2% CO₂ capture with the GE gasifier. An exergy analysis performed for the GE gasifier case revealed that this plant reached 38.9% exergy efficiency, only 1.6%-points below an inflexible GSC-IGCC benchmark configuration, while reaching around 5%-points higher CO₂ capture rate. Near-zero SO_x and NO_x emissions are achieved through pre-combustion gas clean-up and flameless fuel combustion. Overall, this flexible and efficient near-zero emission power plant appears to be a promising alternative in a future carbon constrained world with increasing shares of variable renewables and more stringent pollutant (NO_x, SO_x) regulations.     

Technologies for increasing CO2 concentration in exhaust gas from natural gas-fired power production with post-combustion, amine-based CO2 capture

Enhanced CO₂ concentration in exhaust gas is regarded as a potentially effective method to reduce the high electrical efficiency penalty caused by CO₂ chemical absorption in post-combustion capture systems. The present work evaluates the effect of increasing CO₂ concentration in the exhaust gas of gas turbine based power plant by four different methods: exhaust gas recirculation (EGR), humidification (EvGT), supplementary firing (SFC) and external firing (EFC). Efforts have been focused on the impacts on cycle efficiency, combustion, gas turbine components, and cost. The results show that the combined cycle with EGR has the capability to change the molar fraction of CO₂ with the largest range, from 3.8 mol% to at least 10 mol%, and with the highest electrical efficiency. The EvGT cycle has relatively low additional cost impact as it does not require any bottoming cycle. The externally fired method was found to have the minimum impacts on both combustion and turbomachinery.     

Synergetic effect OF CI engine characteristics when fuelled with neem oil methyl ester enriched with a oxy-hydrogen gas

The Neem-oil methyl ester (NME) produced from transesterification of Neem-oil was mixed with diesel fuel in the share of 10%(N10) and 20%(N20) were used with varying flow rate of oxy-hydrogen gas (HHO) gas at 5%,10% and 15% energy share along with exhaust gas recirculation (EGR) in a 3.7 kW CI engine. Presence of fuel-borne oxygen in NME, facilitates increase in brake thermal efficiency (BTE) at high load related to neat diesel operation. Further the BTE was improved by introducing varying flow rate of HHO gas in order to maintain energy share of 5, 10 and 15% at all loads. The BTE was found as 33.80% and 35.40% for N20 + 10%HHO and N20 + 15%HHO compared to 31.5%, 30.4% and 29.4% for N20, N10 and Neat diesel fuel respectively. Significant emission reduction of CO, CO₂, uHC and smoke opacity were observed during NME + HHO gas operation, but NOx emission was augmented which was controlled using EGR along with further improvement in the engine characteristics.     

Evaluating combustion,performance and emission characteristics of diesel engine using karanja oil methyl ester biodiesel blends enriched with HHO gas

With a specific end goal to take care of the worldwide demand for energy, a broad research is done to create alternative and cost effective fuel. The fundamental goal of this examination is to investigate the combustion, performance and emission characteristics of diesel engine using biodiesel blends enriched with HHO gas. The biodiesel blends are gotten by blending KOME obtained from transesterification of karanja oil in various proportions with neat diesel. The HHO gas is produced by the electrolysis of water in the presence of sodium bicarbonate electrolyte. The constant flow of HHO gas accompanied with biodiesel guarantees lessened brake specific fuel consumption by 2.41% at no load and 17.53% at full load with increased the brake thermal efficiency by 2.61% at no load and 21.67% at full load contrasted with neat diesel operation. Noteworthy decline in unburned hydrocarbon, carbon monoxide, carbon-dioxide emissions and particulate matter with the exception of NO_x discharge is encountered. The addition of EGR controls this hike in NO_x with a slight decline in the performance characteristics. It is clear that the addition of HHO gas with biodiesel blends along with EGR in the test engine improved the overall characterization of engine.     

Effect of induction on exhaust gas recirculation and hydrogen gas in compression ignition engine with simarouba oil in dual fuel mode

Biofuels extracted from non-edible oil is sustainable and can be used as an alternative fuel for internal combustion engines. This study presents the performance, emission and combustion characteristic analysis by using simarouba oil (obtained from Simarouba seed) as an alternative fuel along with hydrogen and exhaust gas recirculation (EGR) in a compression ignition (CI) engine operating on dual fuel mode. Simarouba biofuel blend (B20) was prepared on volumetric basis by mixing simarouba oil and diesel in the proportion of 20% and 80% (v/v), respectively. Hydrogen gas was introduced at the flow rate of 2.67 kg/min, and EGR concentration was maintained at 30% of total air introduction. Performance, combustion and emission characteristics analysis were examined with biodiesel (B20), biodiesel with hydrogen substitution and biodiesel, hydrogen with EGR and were compared with neat diesel operation. Results indicate that BTE of the engine operating with biodiesel B20 was decreased when compared to neat diesel operation. However, introducing hydrogen along with B20 blend into the combustion chamber shows a slight increase in the BTE by 1%. NO_x emission was increased to 18.13% with the introduction of hydrogen than that of base fuel (diesel) operation. With the introduction of EGR, there is a significant reduction in NO_x emission due to decrease in in-cylinder temperature by 19.07%. A significant reduction in CO, CO_2, and smoke emissions were also noted with the introduction of both hydrogen and EGR. The ignition delay and combustion duration were increased with the introduction of hydrogen, EGR with biodiesel than neat diesel operation. Hence, the proposed biodiesel B20 with H₂ and EGR combination can be applied as an alternative fuel in CI engines.     

Optimal greenhouse gas emissions in NGCC plants integrating life cycle assessment

The optimal design of an energy-intensive process involves a compromise between costs and greenhouse gas emissions, complicated by the interaction between optimal process emissions and supply chain emissions. We propose a method that combines generic abatement cost estimates and the results of existing (LCA) life cycle assessment studies, so that supply chain emissions are properly handled during optimization. This method is illustrated for a (NGCC) natural gas combined cycle power plant model with the following design and procurement options: procurement of natural gas from low-emissions producers, fuel substitution with (SNG) synthetic natural gas from wood, and variable-rate CO₂ capture and sequestration from both the NGCC and SNG plants. Using multi-objective optimization, we show two Pareto-optimal sets with and without the proposed LCA method. The latter can then be shown to misestimate CO₂ abatement costs by a few percent, penalizing alternate fuels and energy-efficient process configurations and leading to sub-optimal design decisions with potential net losses of the order of $1/MWh. Thus, the proposed LCA method can enhance the economic analysis of emissions abatement technologies and emissions legislation in general.     

Life cycle GHG assessment of fossil fuel power plants with carbon capture and storage

The evaluation of life cycle greenhouse gas emissions from power generation with carbon capture and storage (CCS) is a critical factor in energy and policy analysis. The current paper examines life cycle emissions from three types of fossil-fuel-based power plants, namely supercritical pulverized coal (super-PC), natural gas combined cycle (NGCC) and integrated gasification combined cycle (IGCC), with and without CCS. Results show that, for a 90% CO₂ capture efficiency, life cycle GHG emissions are reduced by 75–84% depending on what technology is used. With GHG emissions less than 170 g/kWh, IGCC technology is found to be favorable to NGCC with CCS. Sensitivity analysis reveals that, for coal power plants, varying the CO₂ capture efficiency and the coal transport distance has a more pronounced effect on life cycle GHG emissions than changing the length of CO₂ transport pipeline. Finally, it is concluded from the current study that while the global warming potential is reduced when MEA-based CO₂ capture is employed, the increase in other air pollutants such as NO_x and NH₃ leads to higher eutrophication and acidification potentials.     

Trade-off in emissions of acid gas pollutants and of carbon dioxide in fossil fuel power plants with carbon capture

This paper investigates the impact of capture of carbon dioxide (CO₂) from fossil fuel power plants on the emissions of nitrogen oxides (NO_X) and sulphur oxides (SO_X), which are acid gas pollutants. This was done by estimating the emissions of these chemical compounds from natural gas combined cycle and pulverized coal plants, equipped with post-combustion carbon capture technology for the removal of CO₂ from their flue gases, and comparing them with the emissions of similar plants without CO₂ capture. The capture of CO₂ is not likely to increase the emissions of acid gas pollutants from individual power plants; on the contrary, some NO_X and SO_X will also be removed during the capture of CO₂. The large-scale implementation of carbon capture is however likely to increase the emission levels of NO_X from the power sector due to the reduced efficiency of power plants equipped with capture technologies. Furthermore, SO_X emissions from coal plants should be decreased to avoid significant losses of the chemicals that are used to capture CO₂. The increase in the quantity of NO_X emissions will be however low, estimated at 5% for the natural gas power plant park and 24% for the coal plants, while the emissions of SO_X from coal fired plants will be reduced by as much as 99% when at least 80% of the CO₂ generated will be captured.     

High quality product gas from biomass steam gasification combined with torrefaction and carbon dioxide capture processes

Gasification is currently recognized as a mature technology to convert biomass into useful and versatile product gas for further energy and fuel applications. However, there are some remaining problems relating to the process operation and process efficiency due to inherent properties of biomass feedstock such as high moisture content, low energy density and high oxygen content. Strategies to improve the efficiency of biomass gasification as well as the quality of product gas are thus required. For this purpose, a combined process of torrefaction, gasification, and carbon dioxide capture is developed and simulated in a commercial simulator to investigate the performance of a biomass gasification coupled with a pre-treatment and a post-treatment processes. The results show that the quality of product gas is enhanced when combining gasification with a torrefaction and a CO₂ capture processes. The heating value of the product gas and the cold gas efficiency are both increased with additional torrefaction. The CO₂ capture process using monoethanolamine offers a CO₂ removal efficiency of about 83% and consequently increase the product gas heating value up to 27%.     

The effects of hydrogen on the combustion,performance and emissions of a turbo gasoline direct-injection engine with exhaust gas recirculation

The effects of hydrogen on the combustion characteristics, thermal efficiency, and emissions of a turbo gasoline direct-injection engine with exhaust gas recirculation (EGR) were investigated experimentally at brake mean effective pressures of 4, 6, and 8 bar at 2000 rpm. Four cases of hydrogen energy fraction (0%, 1%, 3% and 5%) of total fuel energy were studied. Hydrogen energy fraction of total fuel energy was hydrogen energy in the sum of energy of consumed gasoline and added hydrogen. The test results demonstrated that hydrogen addition improved the combustion speed and reduced cycle-to-cycle variation. In particular, cylinder-to-cylinder variation dramatically decreased with hydrogen addition at high EGR rates. This suggests that the operable EGR rate can be widened for a turbo gasoline direct-injection engine. The improved combustion and wider operable EGR rate resulted in enhanced thermal efficiency. However, the turbocharging effect acted in opposition to the thermal efficiency with respect to the EGR rate. Therefore, a different strategy to improve the thermal efficiency with EGR was required for the turbo gasoline direct-injection engine. HC and CO₂ emissions were reduced but NO_X emissions increased with hydrogen addition. The CO emissions as a function of engine load followed different trends that depended on the level of hydrogen addition.     

Hydrogen rich exhaust gas recirculation (H2EGR) for performance improvement and emissions reduction of a compression ignition engine

Hydrogen (H₂), being carbon free energy carrier, is best suitable for compression ignition (CI) engines with better performance and lower carbon derived emissions. Novelty of present study is the employment of low-cost catalyst (alumina) for production of H₂ reformate (hydrogen rich exhaust gas recirculation: H2EGR) in an indigenous catalytic reactor. Experimental tests were carried out on a CI engine under three conditions; base diesel, exhaust gas recirculation (EGR), and H2EGR. Results indicated that brake thermal efficiency of the engine with H2EGR was higher than EGR and comparable with base diesel operation. All carbon-based emissions including smoke emission decreased significantly with H2EGR than diesel and EGR operations. In addition, oxides of nitrogen emission (NO_x) also decreased by about 46% with H2EGR than base diesel operation. It is concluded that H2EGR is a promising option for CI engines for simultaneous reduction of both NO_x and smoke emissions along with the additional benefit of higher efficiency.     

The role of policy instruments for promoting combined heat and power production with low CO2 emissions in district heating systems

Policy instruments clearly influence the choice of production technologies and fuels in large energy systems, including district heating networks. Current Swedish policy instruments aim at promoting the use of biofuel in district heating systems, and at promoting electric power generation from renewable energy sources. However, there is increasing pressure to harmonize energy policy instruments within the EU. In addition, natural gas based combined cycle technology has emerged as the technology of choice in the power generation sector in the EU. This study aims at exploring the role of policy instruments for promoting the use of low CO₂ emissions fuels in high performance combined heat and power systems in the district heating sector. The paper presents the results of a case study for a Swedish district heating network where new large size natural gas combined cycle (NGCC) combined heat and power (CHP) is being built. Given the aim of current Swedish energy policy, it is assumed that it could be of interest in the future to integrate a biofuel gasifier to the CHP plant and co‐fire the gasified biofuel in the gas turbine unit, thereby reducing usage of fossil fuel. The goals of the study are to evaluate which policy instruments promote construction of the planned NGCC CHP unit, the technical performance of an integrated biofuelled pressurized gasifier with or without dryer on plant site, and which combination of policy instruments promote integration of a biofuel gasifier to the planned CHP unit. The power plant simulation program GateCycle was used for plant performance evaluation. The results show that current Swedish energy policy instruments favour investing in the NGCC CHP unit. The corresponding cost of electricity (COE) from the NGCC CHP unit is estimated at 253 SEK MWh^?1, which is lower than the reference power price of 284 SEK MWh^?1. Investing in the NGCC CHP unit is also shown to be attractive if a CO₂ trading system is implemented. If the value of tradable emission permits (TEP) in such as system is 250 SEK tonne^?1, COE is 353 SEK MWh^?1 compared to the reference power price of 384 SEK MWh^?1. It is possible to integrate a pressurized biofuel gasifier to the NGCC CHP plant without any major re‐design of the combined cycle provided that the maximum degree of co‐firing is limited to 27–38% (energy basis) product gas, depending on the design of the gasifier system. There are many parameters that affect the economic performance of an integrated biofuel gasifier for product gas co‐firing of a NGCC CHP plant. The premium value of the co‐generated renewable electricity and the value of TEPs are very important parameters. Assuming a future CO₂ trading system with a TEP value of 250 SEK tonne^?1 and a premium value of renewable electricity of 200 SEK MWh^?1 COE from a CHP plant with an integrated biofuelled gasifier could be 336 SEK MWh^?1, which is lower than both the reference market electric power price and COE for the plant operating on natural gas alone. Copyright © 2005 John Wiley & Sons, Ltd.     

Study on a zero CO2 emission SOFC hybrid power system integrated with OTM using CO2 as sweep gas

A new zero CO₂ emission solid oxide fuel cell (SOFC) hybrid power system integrated with the oxygen ion transport membrane using CO₂ as sweep gas is proposed in this paper. The pure oxygen is picked up from the cathode outlet gas by the oxygen ion transport membrane with CO₂ as sweep gas; the oxy‐fuel combustion mode in the afterburner of SOFC is employed. Because the combustion product gas only consists of CO₂ and steam, CO₂ is easily captured with lower energy consumption by the condensation of steam. With the aspen plus soft, this paper builds the simulation model of the overall SOFC hybrids system with CO₂ capture. The exergy loss distributions of the overall system are analyzed, and the effects of the key operation parameters on the overall system performance are also investigated. The research results show that the new system still has a high efficiency after CO₂ recovery. The efficiency of the new system is around 65.03%, only 1.25 percentage points lower than that of the traditional SOFC hybrid power system(66.28%)without CO₂ capture. The research achievements from this paper will provide the valuable reference for further study on zero CO₂ emission SOFC hybrid power system with higher efficiency. Copyright © 2013 John Wiley & Sons, Ltd.     

Effects of supplementary biomass firing on the performance of combined cycle power generation: A comparison between NGCC and IGCC plants

In the present work, effects of biomass supplementary firing on the performance of fossil fuel fired combined cycles have been analyzed. Both natural gas fired combined cycle (NGCC) and integrated coal gasification combined cycle (IGCC) have been considered in the study. The efficiency of the NGCC plant monotonically reduces with the increase in supplementary firing, while for the IGCC plant the maximum plant efficiency occurs at an optimum degree of supplementary firing. This difference in the nature of variation of the efficiency of two plants under the influence of supplementary firing has been critically analyzed in the paper. The ratings of different plant equipments, fuel flow rates and the emission indices of CO₂ from the plants at varying degree of supplementary firing have been evaluated for a net power output of 200 MW. The fraction of total power generated by the bottoming cycle increases with the increase in supplementary firing. However, the decrease in the ratings of gas turbines is much more than the increase in that of the steam turbines due to the low work ratio of the topping cycle. The NGCC plants require less biomass compared to the IGCC under identical condition. A critical degree of supplementary firing has been identified for the slag free operation of the biomass combustor. The performance parameters, equipment ratings and fuel flow rates for no supplementary firing and for the critical degree of supplementary biomass firing have been compared for the NGCC and IGCC plants.     

A comparison of electricity and hydrogen production systems with CO2 capture and storage. Part A: Review and selection of promising conversion and capture technologies

We performed a consistent comparison of state-of-the-art and advanced electricity and hydrogen production technologies with CO₂ capture using coal and natural gas, inspired by the large number of studies, of which the results can in fact not be compared due to specific assumptions made. After literature review, a standardisation and selection exercise has been performed to get figures on conversion efficiency, energy production costs and CO₂ avoidance costs of different technologies, the main parameters for comparison. On the short term, electricity can be produced with 85–90% CO₂ capture by means of NGCC and PC with chemical absorption and IGCC with physical absorption at 4.7–6.9 €ct/kWh, assuming a coal and natural gas price of 1.7 and 4.7 €/GJ. CO₂ avoidance costs are between 15 and 50 €/t CO₂ for IGCC and NGCC, respectively. On the longer term, both improvements in existing conversion and capture technologies are foreseen as well as new power cycles integrating advanced turbines, fuel cells and novel (high-temperature) separation technologies. Electricity production costs might be reduced to 4.5–5.3 €ct/kWh with advanced technologies. However, no clear ranking can be made due to large uncertainties pertaining to investment and O&M costs. Hydrogen production is more attractive for low-cost CO₂ capture than electricity production. Costs of large-scale hydrogen production by means of steam methane reforming and coal gasification with CO₂ capture from the shifted syngas are estimated at 9.5 and 7 €/GJ, respectively. Advanced autothermal reforming and coal gasification deploying ion transport membranes might further reduce production costs to 8.1 and 6.4 €/GJ. Membrane reformers enable small-scale hydrogen production at nearly 17 €/GJ with relatively low-cost CO₂ capture.     

Methodologies for predicting the part-load performance of aero-derivative gas turbines

Prediction of the part-load performance of gas turbines is advantageous in various applications. Sometimes reasonable part-load performance is sufficient, while in other cases complete agreement with the performance of an existing machine is desirable. This paper is aimed at providing some guidance on methodologies for predicting part-load performance of aero-derivative gas turbines. Two different design models – one simple and one more complex – are created. Subsequently, for each of these models, the part-load performance is predicted using component maps and turbine constants, respectively. Comparisons with manufacturer data are made. With respect to the design models, the simple model, featuring a compressor, combustor and turbines, results in equally good performance prediction in terms of thermal efficiency and exhaust temperature as does a more complex model. As for part-load predictions, the results suggest that the mass flow and pressure ratio characteristics can be well predicted with both methods. The thermal efficiency and exhaust temperature, however, are not well predicted below 60–70% load when using turbine constants and assuming constant efficiencies for turbomachinery.     

Numerical investigation on combustion regulation for a stoichiometric heavy-duty natural gas engine with hydrogen addition considering knock limitation

Aiming to further improve the thermal efficiency and reduce NO_x emissions in the stoichiometric hydrogen-enriched natural gas (NG) engine, a detailed 3-D simulation model of stoichiometric operation heavy-duty NG engine is built based on the actual boundary conditions from high load bench test. The superimposed methods for knock regulation, combustion and emission control, including Miller valve timing, hydrogen volume fraction and EGR rate were proposed and investigated comprehensively. It reveals that the typically bimodal characteristic of heat release rate (HRR) curve is caused by knock, which seriously restricts the performance improvement of stoichiometric NG engine under high load condition. To predict and control the occurrence of the second peak of HHR accurately, a new parameter BI is defined. Moreover, the Miller timing with 20°CA of the intake valve late closing shows better combustion performance within the knock limit, accompanied by a slight increase in NO_x emissions. Additionally, the 5% hydrogen blend, coupled with the Miller cycle, can further enhance the indicated thermal efficiency (ITE) of the NG engine due to the stronger effects on acceleration of laminar flame propagation velocity than the promotion of end-gas auto-ignition. Besides, the great potential of EGR rate for balancing NO_x and ITE is also confirmed in the heavy-duty hydrogen-enriched NG engine adopting Miller cycle. Compared to the original indexes, combing with the regulation strategies of intake valve late closing (20°CA), hydrogen addition (5%) and EGR (17%) are proved to increase the indicated thermal efficiency by 1.89% and reduce NO_x emissions by 11.47% within the knock limit.     

Techno-economic evaluation of the evaporative gas turbine cycle with different CO2 capture options

The techno-economic evaluation of the evaporative gas turbine (EvGT) cycle with two different CO₂ capture options has been carried out. Three studied systems include a reference system: the EvGT system without CO₂ capture (System I), the EvGT system with chemical absorption capture (System II), and the EvGT system with oxyfuel combustion capture (System III). The cycle simulation results show that the system with chemical absorption has a higher electrical efficiency (41.6% of NG LHV) and a lower efficiency penalty caused by CO₂ capture (10.5% of NG LHV) compared with the system with oxyfuel combustion capture. Based on a gas turbine of 13.78 MW, the estimated costs of electricity are 46.1 $/MW h for System I, while 70.1 $/MW h and 74.1 $/MW h for Systems II and III, respectively. It shows that the cost of electricity increment of chemical absorption is 8.7% points lower than that of the option of oxyfuel combustion. In addition, the cost of CO₂ avoidance of System II which is 71.8 $/tonne CO₂ is also lower than that of System III, which is 73.2 $/tonne CO₂. The impacts of plant size have been analyzed as well. Results show that cost of CO₂ avoidance of System III may be less than that of System II when a plant size is larger than 60 MW.