Performance and cost of wet and dry cooling systems for pulverized coal power plants with and without carbon capture and storage

Thermoelectric power plants require significant quantities of water, primarily for the purpose of cooling. Water also is becoming critically important for low-carbon power generation. To reduce greenhouse gas emissions from pulverized coal (PC) power plants, post-combustion carbon capture and storage (CCS) systems are receiving considerable attention. However, current CO₂ capture systems require a significant amount of cooling. This paper evaluates and quantifies the plant-level performance and cost of different cooling technologies for PC power plants with and without CO₂ capture. Included are recirculating systems with wet cooling towers and air-cooled condensers (ACCs) for dry cooling. We examine a range of key factors affecting cooling system performance, cost and plant water use, including the plant steam cycle design, coal type, carbon capture system design, and local ambient conditions. Options for reducing power plant water consumption also are presented.     

Cost and performance of fossil fuel power plants with CO2 capture and storage

CO₂ capture and storage (CCS) is receiving considerable attention as a potential greenhouse gas (GHG) mitigation option for fossil fuel power plants. Cost and performance estimates for CCS are critical factors in energy and policy analysis. CCS cost studies necessarily employ a host of technical and economic assumptions that can dramatically affect results. Thus, particular studies often are of limited value to analysts, researchers, and industry personnel seeking results for alternative cases. In this paper, we use a generalized modeling tool to estimate and compare the emissions, efficiency, resource requirements and current costs of fossil fuel power plants with CCS on a systematic basis. This plant-level analysis explores a broader range of key assumptions than found in recent studies we reviewed for three major plant types: pulverized coal (PC) plants, natural gas combined cycle (NGCC) plants, and integrated gasification combined cycle (IGCC) systems using coal. In particular, we examine the effects of recent increases in capital costs and natural gas prices, as well as effects of differential plant utilization rates, IGCC financing and operating assumptions, variations in plant size, and differences in fuel quality, including bituminous, sub-bituminous and lignite coals. Our results show higher power plant and CCS costs than prior studies as a consequence of recent escalations in capital and operating costs. The broader range of cases also reveals differences not previously reported in the relative costs of PC, NGCC and IGCC plants with and without CCS. While CCS can significantly reduce power plant emissions of CO₂ (typically by 85–90%), the impacts of CCS energy requirements on plant-level resource requirements and multi-media environmental emissions also are found to be significant, with increases of approximately 15–30% for current CCS systems. To characterize such impacts, an alternative definition of the “energy penalty” is proposed in lieu of the prevailing use of this term.     

Biomass-fired cogeneration systems with CO2 capture and storage

In this study, we estimate and analyze the CO₂ mitigation costs of large-scale biomass-fired cogeneration technologies with CO₂ capture and storage. The CO₂ mitigation cost indicates the minimum economic incentive required (e.g. in the form of a carbon tax) to make the cost of a less carbon intensive system equal to the cost of a reference system. If carbon (as CO₂) is captured from biomass-fired energy systems, the systems could in principle be negative CO₂ emitting energy systems. CO₂ capture and storage from energy systems however, leads to reduced energy efficiency, higher investment costs, and increased costs of end products compared with energy systems in which CO₂ is vented. Here, we have analyzed biomass-fired cogeneration plants based on steam turbine technology (CHP-BST) and integrated gasification combined cycle technology (CHP-BIGCC). Three different scales were considered to analyze the scale effects. Logging residues was assumed as biomass feedstock. Two methods were used to estimate and compare the CO₂ mitigation cost. In the first method, the cogenerated power was credited based on avoided power production in stand-alone plants and in the second method the same reference output was produced from all systems. Biomass-fired CHP-BIGCC with CO₂ capture and storage was found very energy and emission efficient and cost competitive compared with other conversion systems.     

Potential for flexible operation of pulverised coal power plants with CO2 capture

Abstract

Fossil-fired plants play an important role in electricity networks as mid-merit plants that can respond relatively quickly to changes in supply and demand. As a consequence, they are required to operate over a wide output range and play an important role in maintaining the quality and security of electricity supply by providing response and reserve capacity. Carbon dioxide capture and storage (CCS) has been identified as a critical technology for future electricity generation from coal in the UK. Although the performance of CCS schemes where CO₂ capture plants are operated at full load has been considered in detail, part load performance is less well understood. Developing a better understanding of part load performance of plants operating with CO₂ capture is crucial in determining their suitability to operate as mid-merit plants. This paper presents an assessment of the potential impact of adding post-combustion CO₂ capture at pulverised-coal power plants. Estimated performance of steam cycles working with post-combustion CO₂ capture plant are presented at full and part load, leading to performance predictions for pulverised-coal power plants operated over a range of loads and with varying levels of CO₂ capture. By adjusting the operation of the capture plant, as well as the boiler/steam cycle, an extended range of operation can be achieved including lower minimum stable generation levels and additional 'pumped storage like' capacity for times of high demand. For example, plant operators can alter the energy penalty for the CO₂ capture plant with an associated change in plant output by reducing the level of CO₂ capture. This can allow extra electricity to be generated and sold when electricity prices are high. With solvent storage it should also be possible to increase power plant output for a number of hours, but without associated increases in CO₂ emissions.     

Techno‐economic analysis of biomass/coal Co‐gasification IGCC systems with supercritical steam bottom cycle and carbon capture

In recent years, integrated gasification combined cycle technology has been gaining steady popularity for use in clean coal power operations with carbon capture and sequestration (CCS). This study focuses on investigating two approaches to improve efficiency and further reduce the greenhouse gas (GHG) emissions. First, replace the traditional subcritical Rankine steam cycle portion of the overall plant with a supercritical steam cycle. Second, add different amounts of biomass as feedstock to reduce emissions. Employing biomass as a feedstock has the advantage of being carbon neutral or even carbon negative if CCS is implemented. However, due to limited feedstock supply, such plants are usually small (2–50 MW), which results in lower efficiency and higher capital and production costs. Considering these challenges, it is more economically attractive and less technically challenging to co‐combust or co‐gasify biomass wastes with low‐rank coals. Using the commercial software, Thermoflow®, this study analyzes the baseline plants around 235 MW and 267 MW for the subcritical and supercritical designs, respectively. Both post‐combustion and pre‐combustion CCS conditions are considered. The results clearly show that utilizing a certain type of biomass with low‐rank coals up to 50% (wt.) can, in most cases, not only improve the efficiency and reduce overall emissions but may be economically advantageous, as well. Beyond a 10% Biomass Ratio, however, the efficiency begins to drop due to the rising pretreatment costs, but the system itself still remains more efficient than from using coal alone (between 0.2 and 0.3 points on average). The CO₂ emissions decrease by about 7000 tons/MW‐year compared to the baseline (no biomass), making the plant carbon negative with only 10% biomass in the feedstock. In addition, implementing a supercritical steam cycle raises the efficiency (1.6 percentage points) and lowers the capital costs ($300/kW), regardless of plant layout. Implementing post‐combustion CCS consistently causes a drop in efficiency (at least 7–8 points) from the baseline and increases the costs by $3000–$4000/kW and In recent years, integrated gasification combined cycle technology has been gaining steady popularity for use in clean coal power operations with carbon capture and sequestration (CCS). This study focuses on investigating two approaches to improve efficiency and further reduce the greenhouse gas (GHG) emissions. First, replace the traditional subcritical Rankine steam cycle portion of the overall plant with a supercritical steam cycle. Second, add different amounts of biomass as feedstock to reduce emissions. Employing biomass as a feedstock has the advantage of being carbon neutral or even carbon negative if CCS is implemented. However, due to limited feedstock supply, such plants are usually small (2–50 MW), which results in lower efficiency and higher capital and production costs. Considering these challenges, it is more economically attractive and less technically challenging to co‐combust or co‐gasify biomass wastes with low‐rank coals. Using the commercial software, Thermoflow®, this study analyzes the baseline plants around 235 MW and 267 MW for the subcritical and supercritical designs, respectively. Both post‐combustion and pre‐combustion CCS conditions are considered. The results clearly show that utilizing a certain type of biomass with low‐rank coals up to 50% (wt.) can, in most cases, not only improve the efficiency and reduce overall emissions but may be economically advantageous, as well. Beyond a 10% Biomass Ratio, however, the efficiency begins to drop due to the rising pretreatment costs, but the system itself still remains more efficient than from using coal alone (between 0.2 and 0.3 points on average). The CO₂ emissions decrease by about 7000 tons/MW‐year compared to the baseline (no biomass), making the plant carbon negative with only 10% biomass in the feedstock. In addition, implementing a supercritical steam cycle raises the efficiency (1.6 percentage points) and lowers the capital costs ($300/kW), regardless of plant layout. Implementing post‐combustion CCS consistently causes a drop in efficiency (at least 7–8 points) from the baseline and increases the costs by $3000–$4000/kW and $0.06–$0.07/kW‐h. The SO_x emissions also decrease by about 190 tons/year (7.6 × 10^?6 tons/MW‐year). Finally, the CCS cost is around $65–$72 per ton of CO₂. For pre‐combustion CCS, sour shift appears to be superior both economically and thermally to sweet shift in the current study. Sour shift is always cheaper, (by a difference of about $600/kW and $0.02‐$0.03/kW‐h), easier to implement, and also 2–3 percentage points more efficient. The economic difference is fairly marginal, but the trend is inversely proportional to the efficiency, with cost of electricity decreasing by 0.5 cents/kW‐h from 0% to 10% biomass ratio (BMR) and rising 2.5 cents/kW‐h from 10% to 50% BMR. Pre‐combustion CCS plants are smaller than post‐combustion ones and usually require 25% less energy for CCS due to their compact size for processing fuel flow only under higher pressure (450 psi), versus processing the combusted gases at near‐atmospheric pressure. Finally, the CO₂ removal cost for sour shift is around $20/ton, whereas sweet shift's cost is around $30/ton, which is much cheaper than that of post‐combustion CCS: about $60–$70/ton. Copyright © 2014 John Wiley & Sons, Ltd.     

Thermoeconomic analysis of pressurized hybrid SOFC systems with CO2 separation

In this paper, the results of the thermodynamic and economic analyses of distributed power generation plants (1.5 MWe) are described and compared. The results of an exergetic analysis are also reported, as well as the thermodynamic details of the most significant streams of the plants. The integration of different hybrid solid oxide fuel cell (SOFC) system CO₂ separation technologies characterizes the power plants proposed. A hybrid system with a tubular SOFC fed with natural gas with internal reforming has been taken as reference plant. Two different technologies have been considered for the same base system to obtain a low CO₂ emission plant. The first technology involved a fuel decarbonization and CO₂ separation process placed before the system feed, while the second integrated the CO₂ separation and the energy cycle. The first option employed fuel processing, a technology (amine chemical absorption) viable for short-term implementation in real installations while the second option provided the CO₂ separation by condensing the steam from the system exhaust. The results obtained, using a Web-based Thermo Economic Modular Program software, developed by the Thermochemical Power Group of the University of Genoa, showed that the thermodynamic and economic impact of the adoption of zero emission cycle layouts based on hybrid systems was relevant.     

Directed technical change and the adoption of CO2 abatement technology: The case of CO2 capture and storage

This paper studies the cost-effectiveness of combining traditional environmental policy, such as CO₂-trading schemes, and technology policy that has aims of reducing the cost and speeding the adoption of CO₂ abatement technology. For this purpose, we develop a dynamic general equilibrium model that captures empirical links between CO₂ emissions associated with energy use, directed technical change and the economy. We specify CO₂ capture and storage (CCS) as a discrete CO₂ abatement technology. We find that combining CO₂-trading schemes with an adoption subsidy is the most effective instrument to induce adoption of the CCS technology. Such a subsidy directly improves the competitiveness of the CCS technology by compensating for its markup over the cost of conventional electricity. Yet, introducing R&D subsidies throughout the entire economy leads to faster adoption of the CCS technology as well and in addition can be cost-effective in achieving the abatement target.     

Electricity consumption and CO2 capture potential in Spain

In this paper, different electricity demand scenarios for Spain are presented. Population, income per capita, energy intensity and the contribution of electricity to the total energy demand have been taken into account in the calculations. Technological role of different generation technologies, i.e. coal, nuclear, renewable, combined cycle (CC), combined heat and power (CHP) and carbon capture and storage (CCS), are examined in the form of scenarios up to 2050. Nine future scenarios corresponding to three electrical demands and three options for new capacity: minimum cost of electricity, minimum CO₂ emissions and a criterion with a compromise between CO₂ and cost (CO₂-cost criterion) have been proposed. Calculations show reduction in CO₂ emissions from 2020 to 2030, reaching a maximum CO₂ emission reduction of 90% in 2050 in an efficiency scenario with CCS and renewables. The contribution of CCS from 2030 is important with percentage values of electricity production around 22–28% in 2050. The cost of electricity (COE) increases up to 25% in 2030, and then this value remains approximately constant or decreases slightly.     

Capturing CO2 in flue gas from fossil fuel-fired power plants using dry regenerable alkali metal-based sorbent

CO₂ capture and storage (CCS) has received significant attention recently and is recognized as an important option for reducing CO₂ emissions from fossil fuel combustion. A particularly promising option involves the use of dry alkali metal-based sorbents to capture CO₂ from flue gas. Here, alkali metal carbonates are used to capture CO₂ in the presence of H₂O to form either sodium or potassium bicarbonate at temperatures below 100 °C. A moderate temperature swing of 120–200 °C then causes the bicarbonate to decompose and release a mixture of CO₂/H₂O that can be converted into a “sequestration-ready” CO₂ stream by condensing the steam. This process can be readily used for retrofitting existing facilities and easily integrated with new power generation facilities. It is ideally suited for coal-fired power plants incorporating wet flue gas desulfurization, due to the associated cooling and saturation of the flue gas. It is expected to be both cost effective and energy efficient.     

Carbon capture and storage

Carbon capture and storage (CCS) covers a broad range of technologies that are being developed to allow carbon dioxide (CO₂) emissions from fossil fuel use at large point sources to be transported to safe geological storage, rather than being emitted to the atmosphere. Some key enabling contributions from technology development that could help to facilitate the widespread commercial deployment of CCS are expected to include cost reductions for CO₂ capture technology and improved techniques for monitoring stored CO₂. It is important, however, to realise that CCS will always require additional energy compared to projects without CCS, so will not be used unless project operators see an appropriate value for reducing CO₂ emissions from their operations or legislation is introduced that requires CCS to be used. Possible key advances for CO₂ capture technology over the next 50 years, which are expected to arise from an eventual adoption of CCS as standard practice for all large stationary fossil fuel installations, are also identified. These include continued incremental improvements (e.g. many potential solvent developments) as well as possible step-changes, such as ion transfer membranes for oxygen production for integrated gasifier combined cycle and oxyfuel plants.     

Performance of an oxy-fuel combustion CO2 power cycle including blade cooling

The guiding idea behind oxy-fuel combustion power cycles is guaranteeing a high level of performance as can be obtained by today's advanced power plants, together with CO₂ separation in conditions ready for transport and final disposal. In order to achieve all these goals, oxy-combustion – allowing CO₂ separation by simple cooling of the combustion products – is combined with large heat recovery and staged expansions/compressions, making use of new components, technology and materials upgraded from modern gas turbine engines. In order to provide realistic results, the power plant performance should include the effects of blade cooling. In the present work an advanced cooled expansion model has been included in the model of the MATIANT cycle in order to assess the effects of blade cooling on the cycle efficiency. The results show that the penalty in efficiency due to blade cooling using steam from the heat recovery boiler is about 1.4 percentage points, mainly due to the reheat of the steam, which, on the other hand, leads to an improvement in specific work of about 6%.     

The influence of membrane CO2 separation on the efficiency of a coal-fired power plant

In this paper, the influence of membrane separation of CO₂ from flue gases and the impacts of the whole CCS process (CO₂ separation and compression) on the performance of a coal-fired power plant are studied. First, the effects of the characteristics of the membrane (selectivity and permeability) and the parameters of the process (feed and permeate pressure) on two indices, CO₂ recovery rate and CO₂ purity are analysed. Next, a method for determining the minimum power loss and efficiency loss of the power plant as a function of these calculated indices is described. Then, the power requirements and efficiency loss (up to 15.4 percentage points) because of the CCS installation are calculated. A method for reducing these losses through the integration of the CCS installation with the power plant is also proposed. The main aims of the integration are heat exchange between media and a decrease in the CO₂ temperature before compression. Implementing this process can result in a significant reduction of the efficiency loss by 8 percentage points.     

Long-term CO2 emissions reduction target and scenarios of power sector in Taiwan

This study analyses a series of carbon dioxide (CO₂) emissions abatement scenarios of the power sector in Taiwan according to the Sustainable Energy Policy Guidelines, which was released by Executive Yuan in June 2008. The MARKAL-MACRO energy model was adopted to evaluate economic impacts and optimal energy deployment for CO₂ emissions reduction scenarios. This study includes analyses of life extension of nuclear power plant, the construction of new nuclear power units, commercialized timing of fossil fuel power plants with CO₂ capture and storage (CCS) technology and two alternative flexible trajectories of CO₂ emissions constraints. The CO₂ emissions reduction target in reference reduction scenario is back to 70% of 2000 levels in 2050. The two alternative flexible scenarios, Rt4 and Rt5, are back to 70% of 2005 and 80% of 2005 levels in 2050. The results show that nuclear power plants and CCS technology will further lower the marginal cost of CO₂ emissions reduction. Gross domestic product (GDP) loss rate in reference reduction scenario is 16.9% in 2050, but 8.9% and 6.4% in Rt4 and Rt5, respectively. This study shows the economic impacts in achieving Taiwan's CO₂ emissions mitigation targets and reveals feasible CO₂ emissions reduction strategies for the power sector.     

CO2 control technology effects on IGCC plant performance and cost

As part of the USDOE's Carbon Sequestration Program, an integrated modeling framework has been developed to evaluate the performance and cost of alternative carbon capture and storage (CCS) technologies for fossil-fueled power plants in the context of multi-pollutant control requirements. This paper uses the newly developed model of an integrated gasification combined cycle (IGCC) plant to analyze the effects of adding CCS to an IGCC system employing a GE quench gasifier with water gas shift reactors and a Selexol system for CO₂ capture. Parameters of interest include the effects on plant performance and cost of varying the CO₂ removal efficiency, the quality and cost of coal, and selected other factors affecting overall plant performance and cost. The stochastic simulation capability of the model is also used to illustrate the effect of uncertainties or variability in key process and cost parameters. The potential for advanced oxygen production and gas turbine technologies to reduce the cost and environmental impacts of IGCC with CCS is also analyzed.     

Efficiency enhancement of pressurized oxy‐coal power plant with heat integration

The oxy‐coal combustion with carbon dioxide capture and sequestration is among the promising clean coal technologies for reducing CO₂ emissions. Because most of oxy‐coal power plants need to cope with energy penalties from air separation and CO₂ compressor units, the pressurized combustion is added to reduce the electricity demand for the CCS system, and the waste heat of the pressurized flue gas is recovered by the heat integration technique to increase the power generation from steam turbines. Finally, the efficiency enhancement of a 100 MW_e‐scale power plant is successfully validated by Aspen Plus simulation. Copyright © 2014 John Wiley & Sons, Ltd.     

Conceptual design and techno-economic assessment of integrated solar combined cycle system with DSG technology

Direct steam generation (DSG) in parabolic trough collectors causes an increase to competitiveness of solar thermal power plants (STPP) by substitution of oil with direct steam generation that results in lower investment and operating costs. In this study the integrated solar combined cycle system with DSG technology is introduced and techno-economic assessment of this plant is reported compared with two conventional cases. Three considered cases are: an integrated solar combined cycle system with DSG technology (ISCCS-DSG), a solar electric generating system (SEGS), and an integrated solar combined cycle system with HTF (heat transfer fluid) technology (ISCCS-HTF).This study shows that levelized energy cost (LEC) for the ISCCS-DSG is lower than the two other cases due to reducing O&M costs and also due to increasing the heat to electricity net efficiency of the power plant. Among the three STPPs, SEGS has the lowest CO₂ emissions, but it will operate during daytime only.     

Effects of technological learning on future cost and performance of power plants with CO2 capture

This paper demonstrates the concept of applying learning curves in a consistent manner to performance as well as cost variables in order to assess the future development of power plants with CO₂ capture. An existing model developed at Carnegie Mellon University, which had provided insight into the potential learning of cost variables in power plants with CO₂ capture, is extended with learning curves for several key performance variables, including the overall energy loss in power plants, the energy required for CO₂ capture, the CO₂ capture ratio (removal efficiency), and the power plant availability. Next, learning rates for both performance and cost parameters were combined with global capacity projections for fossil-fired power plants to estimate future cost and performance of these power plants with and without CO₂ capture. The results of global learning are explicitly reported, so that they can be used for other purposes such as in regional bottom-up models. Results of this study show that IGCC with CO₂ capture has the largest learning potential, with significant improvements in efficiency and reductions in cost between 2001 and 2050 under the condition that around 3100 GW of combined cycle capacity is installed worldwide. Furthermore, in a scenario with a strict climate policy, mitigation costs in 2030 are 26, 11, 19 €/t (excluding CO₂ transport and storage costs) for NGCC, IGCC, and PC power plants with CO₂ capture, respectively, compared to 42, 13, and 32 €/t in a scenario with a limited climate policy. Additional results are presented for IGCC, PC, and NGCC plants with and without CO₂ capture, and a sensitivity analysis is employed to show the impacts of alternative assumptions on projected learning rates of different systems.     

Can ‘negative net CO2 emissions’ from decarbonised biogas-to-electricity contribute to solving Poland’s carbon capture and sequestration dilemmas?

The article analyses to what extent ‘negative net CO₂ emissions’ from decarbonised biogas-to-electricity can contribute to solving Poland’s carbon capture and sequestration dilemmas. From the criteria-based evaluation of low-carbon power technologies it is found, that biogas-to-electricity is among technologies having increasing production potential in Poland. Therefore, in future biogas will be able to contribute to solving Poland’s CCS dilemmas, because it offers carbon-neutral electricity. Moreover, by applying CCS into biogas-to-electricity the ‘negative net CO₂ emissions’ can be achieved. The article examines three biogas-to-electricity technologies involving CO₂ capture, i.e. biogas-to-biomethane, biogas-to-CHP and biogas-to-electricity via the ORFC cycle. It is emphasised that the ORFC cycle offers low-cost CO₂ separation from a CO₂-H₂ mixture, low O₂-intensity, and the opportunities for advanced mass and energy integration of involved processes. Besides, energy conversion calculations show that the ORFC cycle can offer comparable cycle efficiency with air- and oxy-combustion combined cycles. In regard to the design of biogas-based energy systems it is recommended to include (i) distributed production of biogas in order to avoid costs of long-distance transportation of high-moisture content biomass and (ii) centralised large-scale decarbonised biogas-to-electricity power plants since costs of pipeline transportation of gases are low but large-scale plants could benefit from increased energy and CCS efficiencies.     

Cycle analysis of low and high H2 utilization SOFC/gas turbine combined cycle for CO2 recovery

A major factor in global warming is CO₂ emission from thermal power plants, which burn fossil fuels. One technology proposed to prevent global warming is CO₂ recovery from combustion flue gas and the sequestration of CO₂ underground or near the ocean bed. Solid oxide fuel cell (SOFC) can produce highly concentrated CO₂, because the reformed fuel gas reacts with oxygen electrochemically without being mixed with air in the SOFC. We therefore propose to operate multi-staged SOFCs with high utilization of reformed fuel to obtain highly concentrated CO₂. In this study, we estimated the performance of multi-staged SOFCs considering H₂ diffusion and the combined cycle efficiency of a multi-staged SOFC/gas turbine/CO₂ recovery power plant. The power generation efficiency of our CO₂ recovery combined cycle is 68.5%, whereas the efficiency of a conventional SOFC/GT cycle with the CO₂ recovery amine process is 57.8%.     

Investigation of coal gasification hydrogen and electricity co-production plant with three-reactors chemical looping process

This paper analyzes a novel process for producing hydrogen and electricity from coal, based on chemical looping combustion (CLC) and gas turbine combined cycle, allowing for intrinsic capture of carbon dioxide. The core of the process consists of a three-reactors CLC system, where iron oxide particles are circulated to: (i) oxidize syngas in the fuel reactor (FR) providing a CO₂ stream ready for sequestration after cooling and steam vapor condensation, (ii) reduce steam in the steam reactor (SR) to produce hydrogen, (iii) consume oxygen in the air reactor (AR) from air releasing heat to sustain the thermal balance of the CLC system and to generate electricity. A compacted fluidized bed, composed of two fuel reactors, is proposed here for full conversion of fuel gases in FR. The gasification CLC combined cycle plant for hydrogen and electricity cogeneration with Fe₂O₃/FeAl₂O₄ oxygen carriers was simulated using ASPEN^® PLUS software. The plant consists of a supplementary firing reactor operating up to 1350 °C and three-reactors SR at 815 °C, FR at 900 °C and AR at 1000 °C. The results show that the electricity and hydrogen efficiencies are 14.46% and 36.93%, respectively, including hydrogen compression to 60 bar, CO₂ compression to 121 bar, The CO₂ capture efficiency is 89.62% with a CO₂ emission of 238.9 g/kWh. The system has an electricity efficiency of 10.13% and a hydrogen efficiency of 41.51% without CO₂ emission when supplementary firing is not used. The plant performance is attractive because of high energy conversion efficiency and low CO₂ emission. Key parameters that affect the system performance are also discussed, including the conversion of steam to hydrogen in SR, supplementary firing temperature of the oxygen depleted air from AR, AR operation temperature, the flow of oxygen carriers, and the addition of inert support material to the oxygen carrier.