Comparative assessment of sub-critical versus advanced super-critical oxyfuel fired PF boilers with CO2 sequestration facilities

This work focuses on the techno-economic assessment of bituminous coal fired sub- and super-critical pulverised fuel boilers from an oxyfuel based CO₂ capture point of view. At the initial stage, two conventional power plants with a nominal power output of above 600 MWe based on the above steam cycles are designed, simulated and optimised. Built upon these technologies, CO₂ capture facilities are incorporated within the base plants resulting in a nominal power output of 500 MWe. In this manner, some sensible heat generated in the air separation unit and the CO₂ capture train can be redirected to the steam cycle resulting in a higher plant efficiency. The simulation results of conventional sub- and super-critical plants are compared with their CO₂ capture counterparts to disclose the effect of sequestration on the overall system performance attributes. This systematic approach allows the investigation of the effects of the CO₂ capture on both cycles. In the literature, super-critical plants are often considered for a CO₂ capture option. These, however, are not based on a systematic evaluation of these technologies and concentrate mainly on one or two key features. In this work several techno-economic plant attributes such as the fuel consumptions, the utility usages, the plant performance parameters as well as the specific CO₂ generation and capture rates are calculated and weighed against each other. Finally, an economic evaluation of the system is conducted along with sensitivity analyses in connection with some key features such as discounted cash flow rates, capital investments and plant efficiencies as well as fuel and operating costs.     

Techno-economic assessment of pulverized coal boilers and IGCC power plants with CO<Subscript>2</Subscript> capture

The current studies on power plant technologies suggest that Integrated Gasification Combined Cycle (IGCC) systems are an effective and economic CO₂ capture technology pathway. In addition, the system in conventional configuration has the advantage of being more “CO₂ capture ready” than other technologies. Pulverized coal boilers (PC) have, however, proven high technical performance attributes and are economically often most practical technologies. To highlight the pros and cons of both technologies in connection with an integrated CO₂ capture, a comparative analysis of ultrasupercritical PC and IGCC is carried out in this paper. The technical design, the mass and energy balance and the system optimizations are implemented by using the ECLIPSE chemical plant simulation software package. Built upon these technologies, the CO₂ capture facilities are incorporated within the system. The most appropriate CO₂ capture systems for the PC system selected for this work are the oxy-fuel system and the postcombustion scheme using Monoethanolamine solvent scrubber column (MEA). The IGCC systems are designed in two configurations: Water gas shift reactor and Selexol-based separation. Both options generate CO₂-rich and hydrogen rich-gas streams. Following the comparative analysis of the technical performance attributes of the above cycles, the economic assessment is carried out using the economic toolbox of ECLIPSE is seamlessly connected to the results of the mass and energy balance as well as the utility usages. The total cost assessment is implemented according to the step-count exponential costing method using the dominant factors and/or a combination of parameters. Subsequently, based on a set of assumptions, the net present value estimation is implemented to calculate the breakeven electricity selling prices and the CO₂ avoidance cost.     

Techno-economic assessment of pulverized coal boilers and IGCC power plants with CO2 capture

The current studies on power plant technologies suggest that Integrated Gasification Combined Cycle (IGCC) systems are an effective and economic CO₂ capture technology pathway. In addition, the system in conventional configuration has the advantage of being more “CO₂ capture ready” than other technologies. Pulverized coal boilers (PC) have, however, proven high technical performance attributes and are economically often most practical technologies. To highlight the pros and cons of both technologies in connection with an integrated CO₂ capture, a comparative analysis of ultrasupercritical PC and IGCC is carried out in this paper. The technical design, the mass and energy balance and the system optimizations are implemented by using the ECLIPSE chemical plant simulation software package. Built upon these technologies, the CO₂ capture facilities are incorporated within the system. The most appropriate CO₂ capture systems for the PC system selected for this work are the oxy-fuel system and the postcombustion scheme using Monoethanolamine solvent scrubber column (MEA). The IGCC systems are designed in two configurations: Water gas shift reactor and Selexol-based separation. Both options generate CO₂-rich and hydrogen rich-gas streams. Following the comparative analysis of the technical performance attributes of the above cycles, the economic assessment is carried out using the economic toolbox of ECLIPSE is seamlessly connected to the results of the mass and energy balance as well as the utility usages. The total cost assessment is implemented according to the step-count exponential costing method using the dominant factors and/or a combination of parameters. Subsequently, based on a set of assumptions, the net present value estimation is implemented to calculate the breakeven electricity selling prices and the CO₂ avoidance cost.     

Exergoeconomic and exergoenvironmental evaluation of power plants including CO2 capture

CO₂ capture from power plants, combined with CO₂ storage, is a potential means for limiting the impact of fossil fuel use on the climate. In this paper, three oxy-fuel plants with incorporated CO₂ capture are evaluated from an economic and environmental perspective. The oxy-fuel plants, a plant with chemical looping combustion with near 100% CO₂ capture and two advanced zero emission plants with 100% and 85% CO₂ capture are evaluated and compared to a similarly structured reference plant without CO₂ capture. To complete the comparison, the reference plant is also considered with CO₂ capture incorporating chemical absorption with monoethanolamine. Two exergy-based methods, the exergoeconomic and the exergoenvironmental analyses, are used to determine the cost-related and the environmental impacts of the plants, respectively, and to reveal options for improving their overall effectiveness.For the considered oxy-fuel plants, the investment cost is estimated to be almost double that of the reference plant, mainly due to the equipment used for oxygen production and CO₂ compression. Furthermore, the exergoeconomic analysis reveals an increase in the cost of electricity with respect to the reference plant by more than 20%, with the advanced zero emission plant with 85% CO₂ capture being the most economical choice. On the other hand, a life cycle assessment reveals a decrease in the environmental impact of the plants with CO₂ capture, due to the CO₂ and NO_x emission control. This leads to a reduction in the overall environmental impact of the plants by more than 20% with respect to the reference plant. The most environmentally friendly concept is the plant with chemical looping combustion.     

Techno-economic evaluation of advanced IGCC lignite coal fuelled power plants with CO2 capture

The techno-economic evaluation of four novel integrated gasification combined cycle (IGCC) power plants fuelled with low rank lignite coal with CO₂ capture facility has been investigated using ECLIPSE process simulator. The performance of the proposed plants was compared with two conventional IGCC plants with and without CO₂ capture. The proposed plants include an advanced CO₂ capturing process based on the Absorption Enhanced Reforming (AER) reaction and the regeneration of sorbent materials avoiding the need for sulphur removal component, shift reactor and/or a high temperature gas cleaning process. The results show that the proposed CO₂ capture plants efficiencies were 18.5–21% higher than the conventional IGCC CO₂ capture plant. For the proposed plants, the CO₂ capture efficiencies were found to be within 95.8–97%. The CO₂ capture efficiency for the conventional IGCC plant was 87.7%. The specific investment costs for the proposed plants were between 1207 and 1479 €/kW_e and 1620 €/kW_e and 1134 €/kW_e for the conventional plants with and without CO₂ capture respectively. Overall the proposed IGCC plants are cleaner, more efficient and produce electricity at cheaper price than the conventional IGCC process.     

Partial O2-fired coal power plant with post-combustion CO2 capture: A retrofitting option for CO2 capture ready plants

In the work presented in this paper, an alternative process concept that can be applied as retrofitting option in coal-fired power plants for CO₂ capture is examined. The proposed concept is based on the combination of two fundamental CO₂ capture technologies, the partial oxyfuel mode in the furnace and the post-combustion solvent scrubbing. A 330 MW_el Greek lignite-fired power plant and a typical 600 MW_el hard coal plant have been examined for the process simulations. In a retrofit application of the ECO-Scrub technology, the existing power plant modifications are dominated by techno-economic restrictions regarding the boiler and the steam turbine islands. Heat integration from processes (air separation, CO₂ compression and purification and the flue gas treatment) can result in reduced energy and efficiency penalties. In the context of this work, heat integration options are illustrated and main results from thermodynamic simulations dealing with the most important features of the power plant with CO₂ capture are presented for both reference and retrofit case, providing a comparative view on the power plant net efficiency and energy consumptions for CO₂ capture. The operational characteristics as well as the main figures and diagrams of the plant’s heat balances are included.     

Thermodynamic Simulation of CO2 Capture for an IGCC Power Plant using the Calcium Looping Cycle

A CO₂ capture process for an integrated gasification combined cycle (IGCC) power plant using the calcium looping cycle was proposed. The CO₂ capture process using natural and modified limestone was simulated and investigated with the software package Aspen Plus. It incorporated a fresh feed of sorbent to compensate for the decay in CO₂ capture activity during long‐term cycles. The sorbent flow ratios have significant effect on the CO₂ capture efficiency and net efficiency of the CO₂ capture system. The IGCC power plant, using the modified limestone, exhibits higher CO₂ capture efficiency than that using the natural limetone at the same sorbent flow ratios. The system net efficiency using the natural and modified limestones achieves 41.7 % and 43.1 %, respectively, at the CO₂ capture efficiency of 90 % without the effect of sulfation.     

Cost of energy analysis of integrated gasification combined cycle (IGCC) power plant with respect to CO2 capture ratio under climate change scenarios

This paper presents the results of the cost of energy (COE) analysis of an integrated gasification combined cycle (IGCC) power plant with respect to CO₂ capture ratio under the climate change scenarios. To obtain process data for a COE analysis, simulation models of IGCC power plants and an IGCC with carbon capture and sequestration (CCS) power plant, developed by the United States Department of Energy (DOE) and National Energy Technology Laboratory (NETL), have been adopted and simulated using Aspen Plus. The concept of 20-year levelized cost of energy (LCOE), and the climate change scenarios suggested by International Energy Agency (IEA) are also adopted to compare the COE of IGCC power plants with respect to CO₂ capture ratio more realistically. Since previous studies did not consider fuel price and CO₂ price changes, the reliability of previous results of LCOE is not good enough to be accepted for an economic comparison of IGCC power plants with respect to CO₂ capture ratio. In this study, LCOEs which consider price changes of fuel and CO₂ with respect to the climate change scenarios are proposed in order to increase the reliability of an economic comparison. And the results of proposed LCOEs of an IGCC without CCS power plant and IGCC with CCS (30%, 50%, 70% and 90% capture-mole basis- of CO₂ in syngas stream) power plants are presented.     

Safe storage of Co2 together with improved oil recovery by Co2-enriched water injection

The 2007 IEA's World Energy Outlook report predicts that the world's energy needs will grow by 55% between 2005 and 2030, with fossil fuels accounting for 84% of this massive projected increase in energy demand. An undesired side effect of burning fossil fuels is carbon dioxide (CO₂) emission which is now widely believed to be responsible for the problem of global warming. Various strategies are being considered for addressing the increase in demand for energy and at the same time developing technologies to make energy greener by reducing CO₂ emissions.One of these strategies is to ‘capture’ produced CO₂ instead of releasing it into the atmosphere. Capturing CO₂ and its injection in oil reservoirs can lead to improved oil recovery as well as CO₂ retention and storage in these reservoirs. The technology is referred to as CCS (carbon capture and storage). Large point sources of CO₂ (e.g., coal-fired power plants) are particularly good candidates for capturing large volumes of CO₂. However, CO₂ capture from power plants is currently very expensive. In addition to high costs of CO₂ capture, the very low pressure of the flue gas (1 atm) and its low CO₂ content (typically 10-15%) contribute to the high cost of CO₂ capture from power plants and the subsequent compression. This makes conventional CO₂ flooding (which requires very large volumes of CO₂) uneconomical in many oil reservoirs around the world which would otherwise be suitable candidates for CO₂ injection. Alternative strategies are therefore needed to utilize smaller sources of CO₂ that are usually available around oil and gas fields and can be captured at lower costs (due to their higher pressure and higher CO₂ concentration).We investigate the potential of carbonated (CO₂-enriched) water injection (CWI) as an injection strategy for improving recovery from oil reservoirs with the added benefit of safe storage of CO₂. The performance of CWI was investigated by conducting high-pressure flow visualization as well as coreflood experiments at reservoir conditions. The results show that CWI significantly improves oil recovery from water flooded porous media. A relatively large fraction of the injected CO₂ was retained (stored) in the porous medium in the form of dissolved CO₂ in water and oil. The results clearly demonstrate the huge potential of CWI as a productive way of utilizing CO₂ for improving oil recovery and safe storage of potentially large cumulative quantities of CO₂.     

The multi-period optimisation of an amine-based CO2 capture process integrated with a super-critical coal-fired power station for flexible operation

In this work, we present a model of a super-critical coal-fired power plant integrated with an amine-based CO₂ capture process. We use this model to solve a multi-period dynamic optimisation problem aimed at decoupling the operation of the power plant from the efficiency penalty imposed by the CO₂ capture plant, thus providing the power plant sufficient flexibility to exploit price variation within an electricity market. We evaluate four distinct scenarios: load following, solvent storage, exhaust gas by-pass and time-varying solvent regeneration. The objective is to maximise the decarbonised power plant's short run marginal cost profitability. It is found that while the solvent storage option provides a marginal improvement of 4% in comparison to the load following scenario, the exhaust gas bypass scenario results in a profit reduction of 17% whereas the time-varying solvent regeneration option increases the profitability of the power plant by 16% in comparison to the reference scenario.     

Economic implications of oxyfuel application in a lignite-fired power plant

Scope of the work presented in this paper is to examine and evaluate the application of the oxyfuel combustion CO₂ capture technology in a lignite-fired power plant from an economic point of view. Results from simulations dealing with the most important features for CO₂ reduction are performed. The operational characteristics, the efficiency penalties as well as the net efficiency reduction emerging from the Greenfield application of the oxyfuel technology are presented.CO₂ capture costs and the energy requirements associated with the oxyfuel method affect significantly the cost of electricity. This paper focuses on the analysis of the techno-economic factors that result in the increase of the cost of electricity in comparison with the conventional air-fired power plant. For this reason a typical Greek lignite power plant is used as a reference case. Any technical, economic and financial assumptions applied provide a common basis for both power plants (i.e., conventional and oxyfuel) for the assessment of the change of the cost of electricity and the CO₂ capture cost. The oxyfuel simulations are performed by taking into account the adoption of measures for the exploitation of heat that would otherwise be wasted. Such measures concern both the water/steam cycle and the gas flows (e.g., the oxygen flow). Heat integration from processes - such as the air separation, the CO₂ compression and purification and the flue gas treatment - is adopted in order to lower as much as possible the efficiency penalty.The cycle calculations have been performed using the thermodynamic cycle calculation software ENBIPRO (ENergie-BIllanz-PROgram). ENBIPRO is a powerful tool for heat and mass balance solving of complex thermodynamic circuits, calculation of efficiency, exergetic and exergoeconomic analysis of power plants. The software code models all pieces of equipment that usually appear in power plant installations and can accurately calculate all thermodynamic properties (temperature, pressure, enthalpy) at each node of the thermodynamic circuit, power consumption of each component, flue gas composition, etc. The code has proven its validity by accurately simulating a large number of power plants and through comparison of the results with other commercial software (Stamatelopoulos GN. Calculation and optimisation of power plant thermodynamic cycles. VDI-Regulations. Series 6, No. 340. Braunchweig, Mechanical Engineering Department; 1996 [in German]).     

Optimization of energy usage for fleet‐wide power generating system under carbon mitigation options

This article presents a fleet‐wide model for energy planning that can be used to determine the optimal structure necessary to meet a given CO₂ reduction target while maintaining or enhancing power to the grid. The model incorporates power generation as well as CO₂ emissions from a fleet of generating stations (hydroelectric, fossil fuel, nuclear, and wind). The model is formulated as a mixed integer program and is used to optimize an existing fleet as well as recommend new additional generating stations, carbon capture and storage, and retrofit actions to meet a CO₂ reduction target and electricity demand at a minimum overall cost. The model was applied to the energy supply system operated by Ontario power generation (OPG) for the province of Ontario, Canada. In 2002, OPG operated 79 electricity generating stations; 5 are fueled with coal (with a total of 23 boilers), 1 by natural gas (4 boilers), 3 nuclear, 69 hydroelectric and 1 wind turbine generating a total of 115.8 TWh. No CO₂ capture process existed at any OPG power plant; about 36.7 million tonnes of CO₂ was emitted in 2002, mainly from fossil fuel power plants. Four electricity demand scenarios were considered over a span of 10 years and for each case the size of new power generation capacity with and without capture was obtained. Six supplemental electricity generating technologies have been allowed for: subcritical pulverized coal‐fired (PC), PC with carbon capture (PC+CCS), integrated gasification combined cycle (IGCC), IGCC with carbon capture (IGCC+CCS), natural gas combined cycle (NGCC), and NGCC with carbon capture (NGCC+CCS). The optimization results showed that fuel balancing alone can contribute to the reduction of CO₂ emissions by only 3% and a slight, 1.6%, reduction in the cost of electricity compared to a calculated base case. It was found that a 20% CO₂ reduction at current electricity demand could be achieved by implementing fuel balancing and switching 8 out of 23 coal‐fired boilers to natural gas. However, as demand increases, more coal‐fired boilers needed to be switched to natural gas as well as the building of new NGCC and NGCC+CCS for replacing the aging coal‐fired power plants. To achieve a 40% CO₂ reduction at 1.0% demand growth rate, four new plants (2 NGCC, 2 NGCC+CCS) as well as carbon capture processes needed to be built. If greater than 60% CO₂ reductions are required, NGCC, NGCC+CCS, and IGCC+CCS power plants needed to be put online in addition to carbon capture processes on coal‐fired power plants. The volatility of natural gas prices was found to have a significant impact on the optimal CO₂ mitigation strategy and on the cost of electricity generation. Increasing the natural gas prices resulted in early aggressive CO₂ mitigation strategies especially at higher growth rate demands. © 2009 American Institute of Chemical Engineers AIChE J, 2009     

The calcium looping cycle for CO2 capture from power generation, cement manufacture and hydrogen production

Calcium looping is a CO₂ capture scheme using solid CaO-based sorbents to remove CO₂ from flue gases, e.g., from a power plant, producing a concentrated stream of CO₂ (∼95%) suitable for storage. The scheme exploits the reversible gas-solid reaction between CO₂ and CaO(s) to form CaCO₃(s). Calcium looping has a number of advantages compared to closer-to-market capture schemes, including: the use of circulating fluidised bed reactors—a mature technology at large scale; sorbent derived from cheap, abundant and environmentally benign limestone and dolomite precursors; and the relatively small efficiency penalty that it imposes on the power/industrial process (i.e., estimated at 6-8 percentage points, compared to 9.5-12.5 from amine-based post-combustion capture). A further advantage is the synergy with cement manufacture, which potentially allows for decarbonisation of both cement manufacture and power production. In addition, a number of advanced applications offer the potential for significant cost reductions in the production of hydrogen from fossil fuels coupled with CO₂ capture. The range of applications of calcium looping are discussed here, including the progress made towards demonstrating this technology as a viable post-combustion capture technology using small-pilot scale rigs, and the early progress towards a 2 MW scale demonstrator.     

Control strategies for flexible operation of power plant with CO2 capture plant

About 20% power output penalties will be incurred for implementing CO₂ capture from power plant. This loss can be partially compensated by flexible operation of capture plant. However, daily large variations of liquid and gas flows may cause operation problems to packed columns. Control schemes were proposed to improve the flexibility of power output without causing substantial hydraulic disturbances in capture plant is presented. Simulations were implemented using ASPEN Plus. In varying lean solvent flow strategy, the flow rate of recycling solvent was manipulated to control the CO₂ capture rate. The liquid flow of the absorber and gas flow of the stripper will vary substantially. In an alternative strategy, the lean solvent loading will be varied. Variation of gas throughput in the stripper is avoided by recycling part of CO₂ vapor to stripper. This strategy provided more stable hydraulics condition in both columns and is recommended for flexible operation. © 2011 American Institute of Chemical Engineers AIChE J, 2012     

Simulation of Post‐Combustion CO2 Capture,a Comparison among Absorption,Adsorption and Membranes

Post‐combustion CO₂ capture was studied in the favorable context where the captured CO₂ can be reused in a neighboring industrial process. Three technologies for CO₂ capture, absorption by amines, adsorption on activated carbon, and separation using polymer membranes, were considered, modeled and compared. The three capture processes were designed for achieving the same performances. The models were integrated in a commercial flowsheeting software. The results show that, for a targeted CO₂ purity of 95 %, the membrane process appears to be the least energy consuming. A next step will be to quantify the environmental benefits using life cycle assessment.     

Assessment of chemical looping-based conceptual designs for high efficient hydrogen and power co-generation applied to gasification processes

Carbon capture and storage (CCS) technologies are expected to play a significant role in the coming decades for curbing the greenhouse gas emissions and to ensure a sustainable development of power generation and other energy-intensive industrial sectors. Chemical looping systems are very promising options for intrinsically capture CO₂ with lower cost and energy penalties. Gasification offers significant advantages compared with other technologies in term of lower energy and cost penalties for carbon capture, utilization of wide range of fuels, poly-generation capability, plant flexibility, lower environmental impact, etc.     

Dynamic modelling and analysis of post-combustion CO2 chemical absorption process for coal-fired power plants

Post-combustion capture by chemical absorption using MEA solvent remains the only commercial technology for large scale CO₂ capture for coal-fired power plants. This paper presents a study of the dynamic responses of a post-combustion CO₂ capture plant by modelling and simulation. Such a plant consists mainly of the absorber (where CO₂ is chemically absorbed) and the regenerator (where the chemical solvent is regenerated). Model development and validation are described followed by dynamic analysis of the absorber and regenerator columns linked together with recycle. The gPROMS (Process Systems Enterprise Ltd.) advanced process modelling environment has been used to implement the proposed work. The study gives insights into the operation of the absorber-regenerator combination with possible disturbances arising from integrated operation with a power generation plant. It is shown that the performance of the absorber is more sensitive to the molar L/G ratio than the actual flow rates of the liquid solvent and flue gas. In addition, the importance of appropriate water balance in the absorber column is shown. A step change of the reboiler duty indicates a slow response. A case involving the combination of two fundamental CO₂ capture technologies (the partial oxyfuel mode in the furnace and the post-combustion solvent scrubbing) is studied. The flue gas composition was altered to mimic that observed with the combination. There was an initial sharp decrease in CO₂ absorption level which may not be observed in steady-state simulations.     

Carbon capture from stationary power generation sources: A review of the current status of the technologies

The world will need greatly increased energy supply in the future for sustained economic growth, but the related CO₂ emissions and the resulting climate changes are becoming major concerns. CO₂ is one of the most important greenhouse gases that is said to be responsible for approximately 60% of the global warming. Along with improvement of energy efficiency and increased use of renewable energy sources, carbon capture and sequestration (CCS) is expected to play a major role in curbing the greenhouse gas emissions on a global scale. This article reviews the various options and technologies for CO₂ capture, specifically for stationary power generation sources. Many options exist for carbon dioxide capture from such sources, which vary with power plant types, and include post-combustion capture, pre-combustion capture, oxy fuel combustion capture, and chemical looping combustion capture. Various carbon dioxide separation technologies can be utilized with these options, such as chemical absorption, physical absorption, adsorption, and membrane separation. Most of these capture technologies are still at early stages of development. Recent progress and remaining challenges for the various CO₂ capture options and technologies are reviewed in terms of capacity, selectivity, stability, energy requirements, etc. Hybrid and modified systems hold huge future potentials, but significant progress is required in materials synthesis and stability, and implementations of these systems on demonstration plants are needed. Improvements and progress made through applications of process systems engineering concepts and tools are highlighted and current gaps in the knowledge are also mentioned. Finally, some recommendations are made for future research directions.     

Initial evaluation of the impact of post-combustion capture of carbon dioxide on supercritical pulverised coal power plant part load performance

Pulverised coal-fired plants often play an important role in electricity grids as mid-merit plants that can operate flexibly in response to changes in supply and demand. As a consequence, these plants are required to operate over a wide output range. This paper presents an initial evaluation of some potential impacts of adding post-combustion CO₂ capture on the part load performance of pulverised coal-fired plants. Preliminary results for ideal cases analysed using a simple high-level model indicate that post-combustion CO₂ capture could increase the options available to power plant operators. In particular, solvent storage could allow higher effective plant load factors to be achieved to assist with capital recovery while still permitting flexible operation for grid support. A number of areas for more detailed analysis are identified.     

Integration of a chemical process model in a power plant modelling tool for the simulation of an amine based CO2 scrubber

Post-combustion is considered among the different options for CO₂ capture as the most mature available technology. All major components of the CO₂ absorption/desorption process are commercially available but at a smaller scale, and they are not integrated and optimized for the application in power plants. Therefore, it is still to be demonstrated that this process is a viable option for the capture of CO₂ at power plants. The amine scrubbing process with standard solvents is highly energy demanding due to solvent regeneration and CO₂ compression. This is a significant energy sink for the power plant and efficiency can be reduced up to 16%-points. In order to minimise the energy penalty, complete integration and optimization of the capture and the power plant processes are necessary.Simulations of the power plant cycle and the amine scrubbing system have been performed with specialized software. The results of the integration are discussed.