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 CO 2 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.     

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.     

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.     

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.     

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     

Rigorous-simulation pinch-technology refined approach for process synthesis of the water-gas shift reaction system in an IGCC process with carbon capture

Integrated gasification combined cycle (IGCC) technology is becoming increasingly more competitive among advanced power generation systems suitable for carbon capture. As an emerging technology, many different IGCC process configurations have been heuristically proposed to meet even more aggressive economic and environmental goals. One attractive design combines gasification with a water-gas shift (WGS) reaction system, pressure swing adsorption, and chemical-looping combustion (CLC) for CO₂ removal prior to feeding the fuel gas to the combined cycle for power production. The WGS reaction step is required to convert CO to CO₂ and the extent of conversion is determined by the degree of carbon capture required in the CLC step. As a first towards optimizing the overall energy efficiency of this IGCC process, we apply heat exchanger network synthesis (HENS) to the WGS reaction system. This particular part of the process was chosen because of its evident integration potential (steam required for the WGS reactions can be generated by recovering energy released by the same reactions) and the influence of some of the gasifier parameters (temperature and pressure) on its performance and on all the subsequent parts of the process. After generating alternative designs using Aspen Energy Analyzer (AEA), the HENS problem was formulated in the sequential-modular Aspen Plus simulator using a process superstructure approach and solved by mixed integer nonlinear programming (MINLP) algorithms. The HENS capability is implemented as CAPE-OPEN (CO) compliant unit operation and makes use of MINLP algorithms, namely Generalized Bender's Decomposition (GBD), Outer Approximation (OA), Equality Relaxation (ER), Augmented Penalty (AP), and Simulated Annealing (SA). This MINLP-based HENS was used in the CO-compliant Aspen Plus simulator to obtain a design for the WGS reaction system that provided a cost of energy for the IGCC system with CO₂ capture that was 28% lower than the base case.     

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.     

Progress in carbon dioxide capture and separation research for gasification-based power generation point sources

The purpose of the present work is to investigate novel approaches, materials, and molecules for the abatement of carbon dioxide (CO₂) at the pre-combustion stage of gasification-based power generation point sources. The capture/separation step for CO₂ from large point sources is a critical one with respect to the technical feasibility and cost of the overall carbon sequestration scenario. For large point sources, such as those found in power generation, the carbon dioxide capture techniques being investigated by the Office of Research and Development of the National Energy Technology Laboratory possess the potential for improved efficiency and reduced costs as compared to more conventional technologies. The investigated techniques can have wide applications, but the present research is focused on the capture/separation of carbon dioxide from fuel gas (pre-combustion gas) from processes such as the Integrated Gasification Combined Cycle (IGCC) process. For such applications, novel concepts are being developed in wet scrubbing with physical sorption, chemical sorption with solid sorbents, and separation by membranes. In one concept, a wet scrubbing technique is being investigated that uses a physical solvent process to remove CO₂ from fuel gas of an IGCC system at elevated temperature and pressure. The need to define an “ideal” solvent has led to the study of the solubility and mass transfer properties of various solvents. Pertaining to another separation technology, fabrication techniques and mechanistic studies for membranes separating CO₂ from the fuel gas produced by coal gasification are also being performed. Membranes that consist of CO₂-philic ionic liquids encapsulated into a polymeric substrate have been investigated for permeability and selectivity. Finally, processes based on dry, regenerable sorbents are additional techniques for CO₂ capture from fuel gas. An overview of these novel techniques is presented along with a research progress status of technologies related to membranes and physical solvents.     

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.     

A technical and environmental analysis of co-combustion of coal and biomass in fluidised bed technologies

The use of biomass, which is considered to produce no net CO₂ emissions in its life cycle, can reduce the effective CO₂ emissions of a coal-fired power generation system, when co-fired with the coal, but may also reduce system efficiency.The technical and environmental analysis of fluidised bed technologies, using the ECLIPSE suite of process simulation software, is the subject of this study. System efficiencies for generating electricity are evaluated and compared for the different technologies and system scales.Several technologies could be applied to the co-combustion of biomass or waste and coal. The assessment studies here examine the potential for co-combustion of (a) a 600 MWe pulverised fuel (PF) power plant (as a reference system), (i) co-firing coal with straw and sewage sludge and (ii) using straw derived fuel gas as return fuel; (b) a 350 MWe pressurised fluidised bed combustion (PFBC) system co-firing coal with sewage sludge; (c) 250 MWe and 125 MWe circulating fluidised bed combustion (CFBC) plants co-firing coal with straw and sewage sludge; (d) 25 MWe CFBC systems co-firing low and high sulphur content coal with straw, wood and woody matter pressed from olive stones (WPOS); (e) 12 MWe CFBC co-firing low and high sulphur content coal with straw or wood; and (f) 12 MWe bubbling fluidised bed combustion (BFBC), also co-firing low and high sulphur content coal with straw or wood.In the large systems the use of both straw and sewage sludge resulted in a small reduction in efficiency (compared with systems using only coal as fuel).In the small-scale systems the high moisture content of the wood chips chosen caused a significant efficiency reduction.Net CO₂ emissions are reduced when biomass is used, and these are compared for the different types and scales of fluidised bed technologies. NO_x emissions were affected by a number of factors, such as bed temperature, amount of sorbent used for SO₂ capture and HCl emitted.     

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.     

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.     

A Techno-economic assessment of the reduction of carbon dioxide emissions through the use of biomass co-combustion

Using sustainably-grown biomass as the sole fuel, or co-fired with coal, is an effective way of reducing the net CO₂ emissions from a combustion power plant. There may be a reduction in efficiency from the use of biomass, mainly as a result of its relatively high moisture content, and the system economics may also be adversely affected.The economic cost of reducing CO₂ emissions through the replacement of coal with biomass can be identified by analysing the system when fuelled solely by biomass, solely by coal and when a coal-biomass mixture is used.The technical feasibility of burning biomass or certain wastes with pulverised coal in utility boilers has been well established. Cofiring had also been found to have little effect on efficiency or flame stability, and pilot plant studies had shown that cofiring could reduce NO_x and SO_x emissions.Several technologies could be applied to the co-combustion of biomass or waste and coal. The assessment studies here examine the potential for co-combustion of (a) a 600 MWe pulverised fuel (PF) power plant, (i) cofiring coal with straw and sewage sludge and (ii) using straw derived fuel gas as return fuel; (b) a 350 MWe pressurised fluidised bed combustion (PFBC) system cofiring coal with sewage sludge; (c) 250 and 125 MWe circulating fluidised bed combustion (CFBC) plants cofiring coal with straw and sewage sludge; (d) 25 MWe CFBC systems cofiring low and high sulphur content coal with straw, wood and woody matter pressed from olive stones (WPOS); and (e) 12 MWe CFBC cofiring low and high sulphur content coal with straw.The technical, environmental and economic analysis of such technologies, using the ECLIPSE suite of process simulation software, is the subject of this study. System efficiencies for generating electricity are evaluated and compared for the different technologies and system scales. The capital costs of systems are estimated for coal-firing and also any additional costs introduced when biomass is used. The Break-even electricity selling price is calculated for each technology, taking into account the system scale and fuel used.Since net CO₂ emissions are reduced when biomass is used, the effect of the use of biomass on the electricity selling price can be found and the premium required for emissions reduction assessed. Consideration is also given to the level of subvention required, either as a Carbon dioxide Credit or as a Renewable Credit, to make the systems using biomass competitive with those fuelled only with coal.It would appear that a Renewable Credit (RC) is a more transparent and cost-effective mechanism to support the use of biomass in such power plants than a Carbon dioxide Credit (CC).     

Using short‐term resource scheduling for assessing effectiveness of CCS within electricity generation subsector

A new methodology for assessing the effectiveness of carbon capture and storage (CCS) that does explicitly consider the detailed operation of the target electricity system is proposed. The electricity system simulation consists of three phases, each one using a modified version of an economic dispatch problem that seeks to maximize the producers’ and consumers’ surplus while satisfying the technical constraints of the system. The economic dispatch is formulated as a dynamic mixed‐integer nonlinear programming problem and implemented in general algebraic modelling system (GAMS). The generating unit with CCS is designed and simulated using Aspen Plus®. In the first case study, the operation of the IEEE RTS ’96 (Institute of Electrical and Electronics Engineers One‐Area Reliability Test System—1996) is simulated with greenhouse gas (GHG) regulation implemented in the form of CO₂ permits that generators need to acquire for every unit of CO₂ that it is emitted. In the second case study, CCS is added at one of the buses and the operation of the modified IEEE RTS ’96 is again simulated with and without GHG regulation. The results suggest that the detailed operation of the target electricity system should be considered in future assessments of CCS and a general procedure for undertaking this for any GHG mitigation option is proposed. Future work will use the novel methodology for assessing the effectiveness of generating units with flexible CO₂ capture. © 2015 American Institute of Chemical Engineers AIChE J, 61: 4210–4234, 2015     

Heat integration and analysis of decarbonised IGCC sites

Integrated gasification combined cycle (IGCC) power generation systems have become of interest due to their high combined heat and power (CHP) generation efficiency and flexibility to include carbon capture and storage (CCS) in order to reduce CO₂ emissions. However, IGCC's biggest challenge is its high cost of energy production. In this study, decarbonised coal IGCC sites integrated with CCS have been investigated for heat integration and economic value analyses. It is envisaged that the high energy production cost of an IGCC site can be offset by maximising site-wide heat recovery and thereby improving the cost of electricity (COE) of CHP generation. Strategies for designing high efficiency CHP networks have been proposed based on thermodynamic heuristics and pinch theory. Additionally, a comprehensive methodology to determine the COE from a process site has been developed. In this work, we have established thermodynamic and economic comparisons between IGCC sites with and without CCS and a trade-off between the degree of decarbonisation and the COE from the heat integrated IGCC sites. The results show that the COE from the heat integrated decarbonised IGCC sites is significantly lower compared to IGCC sites without heat integration making application of CCS in IGCC sites economically competitive.     

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.     

Optimal strategy for carbon capture and storage infrastructure: A review

To effectively reduce CO₂, CO₂ mitigation technologies should be employed tactically. This paper focuses on carbon capture and storage (CCS) as the most promising CO₂ reduction technology and investigates how to establish CCS strategy suitably. We confirm a major part of the optimal strategy for CCS infrastructure planning through a literature review according to mathematical optimization criteria associated with facility location models. In particular, the feasibility of large scale CCS infrastructure is evaluated through economic, environmental, and technical assessment. The current state-of-the-art optimization techniques for CCS infrastructure planning are also addressed while taking numerous factors into account. Finally, a list of issues for future research is highlighted.     

Large‐scale optimization strategies for pressure swing adsorption cycle synthesis

Pressure swing adsorption (PSA) is an efficient method for gas separation and is a potential candidate for carbon dioxide (CO₂) capture from power plants. However, few PSA cycles have been designed for this purpose; the optimal design and operation of PSA cycles for CO₂ capture, as well as other systems, remains a very challenging task. In this study, we present a systematic optimization‐based formulation for the synthesis and design of novel PSA cycles for CO₂ capture in IGCC power plants, which can simultaneously produce hydrogen (H₂) and CO₂ at high purity and high recovery. Here, we apply a superstructure‐based approach to simultaneously determine optimal cycle configurations and design parameters for PSA units. This approach combines automatic differentiation, efficient ODE solvers for the state and sensitivity equations of the PSA model, and state of the art nonlinear programming solvers. Three optimization models are proposed, and two PSA case studies are considered. The first case study considers a binary separation of H₂ and CO₂ at high purity, where specific energy is minimized, whereas the second case study considers a larger five component separation. © 2012 American Institute of Chemical Engineers AIChE J, 58: 3777–3791, 2012