Modelling of an IGCC plant with carbon capture for 2020

Currently several industrial scale IGCC - carbon capture demonstration plants are being planned. Thermodynamic simulations are a useful tool to investigate the optimal plant configuration. In order to demonstrate the potential of the next generation of IGCC with CCS a thermodynamic model was developed using conventional but improved technology. The plant concept was verified and simulated for a generic hard coal and lignite. The simulation showed a net efficiency (LHV) of 38.5% and 41.9% for hard coal and lignite, respectively.The results are consistent with current studies but also indicate that major simulations were too optimistic. The auxiliary demand of an IGCC plant with carbon capture can be expected with 21 to 24% based on gross output. The drop in efficiency compared to the none-capture case is estimated with roughly 11 to 12%-points. During a sensitivity study the impact of process changes on plant efficiency and economics is evaluated. Releasing the captured CO₂ without compression is found to be economically favourable at CO₂ prices below 15 €/t and electricity prices above 100 €/MWh. Further the impact of carbon capture rate is quantified and an efficiency potential is indicated for lower CO₂ quality.     

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.     

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 evaluation of a PVAm CO2-selective membrane in an IGCC power plant with CO2 capture

Published data for an operating power plant, the ELCOGAS 315 MWe Puertollano plant, has been used as a basis for the simulation of an integrated gasification combined cycle process with CO₂ capture. This incorporated a fixed site carrier polyvinylamine membrane to separate the CO₂ from a CO-shifted syngas stream. It appears that the modified process, using a sour shift catalyst prior to sulphur removal, could achieve greater than 85% CO₂ recovery at 95 vol% purity. The efficiency penalty for such a process would be approximately 10% points, including CO₂ compression. A modified plant with CO₂ capture and compression was calculated to cost €2320/kW, producing electricity at a cost of 7.6 € cents/kWh and a CO₂ avoidance cost of about €40/tonne CO₂.     

Competitiveness of CO2 capture from an industrial solid oxide fuel cell combined heat and power system in the early stage of market introduction

In this article, it was investigated whether potentially low-cost CO₂ capture from SOFC systems could enhance the penetration of SOFC in the energy market in a highly carbon-constrained society in the mid-term future (up to year 2025). The application of 5 MWe SOFC systems for industrial combined heat and power (CHP) generation was considered. For CO₂ capture, oxyfuel combustion of anode off-gas using commercially available technologies was selected. Gas turbine (GT-) CHP plant was considered to be the reference case.Technical results showed that despite the energy penalties due to CO₂ capture and compression, net electrical and heat efficiencies were nearly identical with or without CO₂ capture. This was due to higher heat recovery efficiency by separating SOFC off-gas streams for CO₂ capture. However, CO₂ capture significantly increased the required SOFC and heat exchanger areas.Economic results showed that for above 40-50 $ t⁻¹ CO₂ price, SOFC-CHP systems were more economical when equipped with CO₂ capture. CO₂ capture also enabled SOFC-CHP to compete with GT-CHP at higher cell stack production costs. At zero CO₂ price, cell stack production cost had to be as low as 140 kW⁻¹ for SOFC-CHP to outperform GT-CHP. At 100 $ t⁻¹ CO₂ price, the cell stack production cost requirement raised to 350 $ kW⁻¹. With CO₂ capture, SOFC-CHP still outperformed GT-CHP at a significantly higher cell stack production cost above 900 $ kW⁻¹.     

Techno-economic optimization of IGCC integrated with utility system for CO2 emissions reduction—Maximum power production in IGCC

Environmental legislation, with its increasing pressure on the energy sector to control greenhouse gases, is a driving force to reduce CO₂ emissions. In this paper, pre-combustion CO₂ capture through integration of a site utility system with an integrated gasification combined cycle (IGCC) is investigated as an option to provide a compressed CO₂-rich stream from a process site for sequestration. This work presents a two-step procedure for integration and optimization of a site utility system with an IGCC plant: (i) screening and optimization of IGCC plant performance parameters; (ii) integration and optimization of the utility system of the site with the IGCC plant. In the first step, an optimization approach applies the results of screening studies based on rigorous simulation of the IGCC. Having fixed the inlet fuel flow rate, the IGCC design parameters (including oxygen consumption, diluent flow rate and turbine exit pressure) are optimized for maximum power generation. Energy flows between the IGCC and CO₂ compression train are considered. In the second step, the economic and operating performance of the utility system integrated with the IGCC plant are modeled and optimized for minimum operating cost to find the most appropriate level of integration. In a case study illustrating the approach, 94% of the fuel is gasified; additional power generation offsets the operating costs of pre-combustion CO₂ capture.     

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.     

Techno-economic study of CO2 capture and storage in coal fired oxygen fed entrained flow IGCC power plants

The attractiveness of fossil fuel as a feedstock for power generation depends on the development of energy conversion systems that are efficient, clean and economical. Coal fired power plants are generally considered to be “dirty” since they have high CO₂ emissions, with the exception of those coal fired power plants that employ CO₂ capture technology. Among the coal fired options, Integrated Gasification Combined Cycle (IGCC) systems have the best environmental performance and are potentially suitable candidates. The objective of this work is to provide an assessment and analysis of the potential for reduction of the output of greenhouse gas from the oxygen fed entrained flow gasifier systems, including the cost and cost-effectiveness of each likely conceptual scheme.     

An economic feasibility study of O2/CO2 recycle combustion technology based on existing coal-fired power plants in China

In order to reduce the CO₂ emission from the coal-fired power plants, O₂/CO₂ recycle combustion (Oxy-combustion) technique has been proposed through combining a conventional combustion process with a cryogenic air separation process. The technique is capable of enriching CO₂ concentration and then allowing CO₂ sequestration in an efficient and energy-saving way. Taking into account the CO₂ taxation and CO₂ sale, the paper evaluates the economic feasibility of Oxy-combustion plants retrofitted from two typical existing conventional coal-fired power plants (with capacities of 2 × 300 MW and 2 × 600 MW, respectively) with Chinese data. The cost of electricity (COE) and the CO₂ avoidance cost (CAC) are also considered in the evaluation. The COE of the retrofitted Oxy-combustion plant is nearly the same as that of the corresponding conventional plant if the unit price of CO₂ sale reaches 17-22 $/t (different cases). The CAC of the retrofitted 2 × 300 MW Oxy-combustion plant is 1-3 $/t bigger than that of the retrofitted 2 × 600 MW Oxy-combustion plant. Supercritical plants are more economical and appropriate for Oxy-combustion retrofit. The result indicates that Oxy-combustion technique is not only feasible for CO₂ emission control based on existing power plants but is also cost-effective.     

Syngas combustion in a chemical-looping combustion system using an impregnated Ni-based oxygen carrier

Chemical-looping combustion (CLC) has emerged as a promising option for CO₂ capture because this gas is inherently separated from the other flue gas components and thus no energy is expended for the separation. This technology would have some advantages if it could be adapted for its use with coal as fuel. In this sense, a process integrated by coal gasification and CLC could be used in power plants with low energy penalty for CO₂ capture. This work presents the results obtained in the combustion of syngas as fuel with a Ni-based oxygen carrier prepared by impregnation in a CLC plant under continuous operation. The effect on the oxygen carrier behaviour and the combustion efficiency of several operating conditions was determined in the continuous CLC plant. High combustion efficiencies (～99%), close to the values limited by thermodynamics, were reached at oxygen carrier-to-fuel ratios higher than 5. The temperature in the FR had a significant influence, although high efficiencies were obtained even at 1073 K. The syngas composition had small effect on the combustion, obtaining high and similar efficiencies with syngas fuels of different composition, even in the presence of high CO concentrations. The low reactivity of the oxygen carrier with CO seemed to indicate that the water gas shift reaction acts as an intermediate step in the global reaction of the syngas in a continuous CLC plant. Neither agglomeration nor carbon deposition problems were detected during 50 h of continuous operation in the prototype. The obtained results showed that the impregnated Ni-based oxygen carrier could be used in a CLC plant for the combustion of syngas produced in an integrated gasification combined cycle (IGCC).     

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     

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.     

High-performance oxygen transport membrane reactors integrated with IGCC for carbon capture

Precombustion carbon capture is an effective strategy to reduce large-scale CO₂ emissions, which is mainly used in the area of integrated gasification combined cycle (IGCC) power plants. Oxygen transport membranes (OTMs) were suggested as the air separation unit to produce high purity oxygen for the gasifier. However, the improvement in efficiency was limited. Here, a new IGCC process is reported based on a robust OTM reactor, where the OTM reactor is used behind the coal gasifier. This IGCC-OTM process fulfills syngas oxidation, H₂ production, and carbon capture in one unit, thus a significant decrease of the energy penalty is expectable. The membrane reactor does not use noble metal components, and exhibits high hydrogen production rates, high hydrogen separation factor (10³–10⁴), and stable performance in a gas mixture mimicking real syngas compositions from a coal gasifier with H₂S concentrations up to 1,000 ppm.     

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.     

Impact of liquid absorption process development on the costs of post-combustion capture in Australian coal-fired power stations

Australian power generators produce approximately 170 TWh per annum of electricity using black and brown coals that accounts for 170 Mtonne of CO₂ emissions per annum or over 40% of anthropogenic CO₂ emissions in Australia. This paper describes the results of a techno-economic evaluation of liquid absorption based post-combustion capture (PCC) processes for both existing and new pulverised coal-fired power stations in Australia. The overall process designs incorporate both the case with continuous capture and the case with the flexibility to switch a CO₂ capture plant on or off depending upon the demand and market price for electricity, and addresses the impact of the presently limited emission controls on the process cost. The techno-economic evaluation includes both air and water cooled power and CO₂ capture plants, resulting in cost of power generation for the situations without and with PCC. Whilst existing power plants in Australia are all water cooled sub-critical designs, the new power plants are deemed to range from supercritical single reheat to ultra-supercritical double reheat designs, with a preference for air-cooling. The process evaluation also includes a detailed sensitivity analysis of the thermodynamic properties of liquid absorbent for CO₂ on the overall costs. The results show that for a meaningful decrease in the efficiency and cost penalties associated with the post combustion CO₂ capture, a novel liquid sorbent will need to have heat of absorption/desorption, sensible heat and heat of vaporisation around 50% less in comparison with 30% (w/w) aqueous MEA solvent. It also shows that the impact of the capital costs of PCC processes is quite large on the added cost of generation. The results can be used to prioritise PCC research in an Australian context.     

Intensification of low temperature thermomorphic biphasic amine solvent regeneration for CO2 capture

High-energy requirements for solvent regeneration represent one of the main challenges in the conventional post-combustion capture (PCC) process. Thermomorphic biphasic solvent (TBS), comprising lipophilic amines as the active components, exhibit a liquid–liquid phase separation (LLPS) upon heating, giving rise to extractive behaviour, and thus enhancing desorption at temperatures well below the solvent boiling point. The low regeneration temperature of less than 90 °C together with the high cyclic CO₂ loading capacity, 3–4 mol/kg, of such TBS system permits the use of low temperature and even waste heat for desorption purposes. In order to improve the solvent regeneration process and reduce the commensurate energy demand still further, desorption experiments with various techniques for enhancing CO₂ release in place of gas stripping, such as nucleation, agitation, ultrasonic method, etc., were studied at temperatures in the range of 75–85 °C. Nucleation and agitation both accelerate CO₂ desorption, but regenerability by nucleation only achieves 70–85%, while by agitation attains 80–95%. Ultrasonic desorption also intensifies the solvent regeneration and superior to conventional stripping process. The energy consumption for TBS system with those intensification techniques is only half of that for alkanolamine-based process with steam stripping. Extractive regeneration is another potential method to substitute for stripping and reduce the exergy demands. An extraction process using inert solvent was developed for improving the regeneration efficiency and elevated pressures were applied for reducing the significant volatile solvent loss.     

Technical and economic study of integrated system of solid oxide fuel cell,palladium membrane reactor,and CO2 sorption enhancement unit

This paper deals with the integrated system of solid oxide fuel cell (SOFC), palladium membrane reactor (PMR), and CO₂ sorption enhancement (SE) unit. Three configurations of the SOFC systems fed by biogas are considered, i.e., PMR–SOFC, SE–PMR–SOFC, and SE–PMR–SOFC with a retentate gas recycling (SER–PMR–SOFC). The SOFC system equipped with a conventional reformer (CON–SOFC) is considered as a base case. The simulation results show that the capture of CO₂ in biogas before being fed to PMR (SE–PMR–SOFC) can improve H₂ recovery. The performance of SE–PMR–SOFC can be further enhanced by recycling retentate gas from PMR to CO₂ sorption enhancement unit (SER–PMR–SOFC). Compared to CON–SOFC, both SE–PMR–SOFC and SER–PMR–SOFC give higher power density and thus require smaller stack size (the stack size reduction of 1.55% and 8.27% are observed for SE–PMR–SOFC and SER–PMR–SOFC, respectively). The economic analysis is performed to identify the potential benefits of each SOFC configuration. The results indicate that SE–PMR–SOFC and SER–PMR–SOFC are not cost-effective systems compared with CON–SOFC; however, the capture of CO₂ in these SOFC systems offers an environmental benefit. High %total CO₂ capture and low cost of CO₂ capture are achieved under these SOFC systems.     

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.     

Comparative assessment of coal fired IGCC systems with CO2 capture using physical absorption,membrane reactors and chemical looping

The integrated gasification combined cycle (IGCC) as an efficient power generation technology with lowest specific carbon dioxide emissions among coal power plants is a very good candidate for CO₂ capture resulting in low energy penalties and minimised CO₂ avoidance costs. In this paper, the techno-economic characteristics of four different capture technologies, which are built upon a conventional reference case, are studied using the chemical process simulation package “ECLIPSE”. The technology options considered are: physical absorption, water gas shift reactor membranes and two chemical looping combustion cycles (CLC), which employ single and double stage reactors. The latter system was devised to achieve a more balanced distribution of temperatures across the reactors and to counteract hot spots which lead to the agglomeration and the sintering of oxygen carriers. Despite the lowest efficiency loss among the studied systems, the economic performance of the double stage CLC was outperformed by systems employing physical absorption and water gas shift reactor membranes. Slightly higher efficiencies and lower costs were associated with systems with integrated air separation units. The estimation of the overall capital costs was carried out using a bottom-up approach. Finally, the CO₂ avoidance costs of individual technologies were calculated based on the techno-economic data.