With the push to curb dangerous atmospheric pollutant production, energy generation technologies that reduce greenhouse gas emissions, while still providing adequate electrical supply are of high importance. With major energy infrastructure already in place, developing enhanced pollutant reducing combustor systems for micro gas turbines (MGTs), that can utilize low calorific fuels from renewable resources, is a major goal. The current work focuses on the experimental testing of an optimized two-stage combustor designed to operate with various fuel types, including natural gas and syngas produced via biomass gasification. Atmospheric experimental tests were performed and the results indicate larger flame lift-off heights and slightly higher CO gas emissions levels, while displaying lower NOx gas emissions levels for all thermal loads and air-tofuel equivalence ratios tested, compared to that of the previous combustor designs. Additionally, steady state CFD simulations were conducted and the results are in general good agreement with the experimental data. Overall, the results indicate high fuel flexibility of the combustor, as well as the ability to comply with the NOx emissions limits for a larger range of operating points, compared to that of the previously tested combustors.

Integrated gasification humid air turbine (IGHAT) cycle is an advanced power generation system, combining gasification technology and humid air turbine (HAT) cycle. It draws great attention in the energy field considering its high specific power, high efficiency, and low emission. There are only a few HAT cycle plants and IGHAT cycle is still on the theory research stage. Therefore, the study on control strategies of IGHAT cycle has great significance in the future development of this system. A design method of control strategy is proposed for the unknown gas turbine systems. The control strategy design is summarized after IGHAT control strategy and logic is designed based on the dynamic simulation results and the operation experience of gas turbine power station preliminarily. Then, control logic is configured and a virtual control system of IGHAT cycle is established on the Ovation distribution control platform. The model-in-loop control platform is eventually set up based on the interaction between the simulation model and the control system. A case study is implemented on this model-in-loop control platform to demonstrate its feasibility in the practical industry control system. The simulation of the fuel switching control mode and the power control mode is analyzed. The power in IGHAT cycle is increased by 24.12% and 32.47%, respectively, compared to the ones in the simple cycle and the regenerative cycle. And the efficiency of IGHAT cycle is 1.699% higher than that of the regenerative cycle. Low component efficiency caused by off-design performance and low humidity caused by high pressure are the main limits for system performance. The results of case study show the feasibility of the control strategy design method proposed in this paper.

Carbon capture from advanced integrated gasification combined-cycle (IGCC) processes should outperform conventional coal combustion with subsequent CO2 separation in terms of efficiency and CO2 capture rates. This paper provides a thermodynamic assessment, using an exergy analysis of a syngas redox (SGR) process for generating electricity. The power island of the proposed process uses syngas produced by coal gasification and is then cleaned through a high-temperature gas desulfurization (HGD) process. Hematite (Fe2O3) is used as an oxygen carrier to oxidize the syngas. To achieve a closed-cycle operation, the reduced iron particles are first partially re-oxidized with steam and then fully re-oxidized with pressurized air. One advantage of this design is that the resulting hydrogen (using steam in the re-oxidation section) can be utilized within the same plant or be sold as a secondary product. In the proposed process, diluted hydrogen is combusted in a gas turbine. Heat integration is central to the design. Thus far, the SGR process and the HGD unit are not commercially availiable. To establish a benchmark, the rate of exergy destruction within the SGR process was compared to a coal-fed Shell gasification IGCC design with Selexol-based precombustion carbon capture. Some thermodynamic inefficiencies were found to shift from the gas turbine to the steam cycle and redox system, while the net efficiency remained almost the same. A process simulation was undertaken, using Aspen Plus and the engineering equation solver (EES).

Fuels from low quality feedstock such as biomass and biomass residues are currently discussed with respect to their potential to contribute to a more sustainable electrical power supply. In the present work, we report on the study of generic representative gas mixtures stemming from the gasification of different feedstock, from wood and algae. Two major combustion properties—burning velocities and ignition delay times—were measured for different parameters: (i) for two pressures—1 bar and 3 bar—at a constant preheat temperature T0 = 373 K, to determine burning velocities by applying the cone angle method; and (ii) for elevated pressures—up to 16 bar—in the temperature range between about 1000 and 2000 K, at fuel-equivalence ratios φ of 0.5 and 1.0, to obtain ignition delay times by applying the shock tube method. Additional studies performed in our group on gas mixtures of natural gas, methane, and hydrogen were also taken into account as major components of biogenic gas mixtures. It was found that the reaction behavior of the wood gasification product (N2, CO, H2, CO2, CH4) is mainly determined by its H2 content, besides CH4; methane determines the kinetic behavior of the algae fermentation product (CH4, CO2, N2) due to its relatively high amount. Detailed chemical kinetic reaction models were used to predict the measured data. The trends and main features were captured by predictions applying different reaction models. The agreement of the experiments and the predictions is dependent on the pressure range.

Even though almost all components of an integrated gasification combined cycle (IGCC) power plant are proven and mature technologies, the sheer number of them, the wide variety of competing technologies (e.g., gasifiers, gas clean-up systems, heat recovery options), and system integration options (e.g., cryogenic air separation unit and the gas turbine), including the recent addition of carbon capture and sequestration (CCS) with its own technology and integration options, render fundamental IGCC performance analysis a monumental task. Almost all published studies utilize highly complex chemical process and power plant heat balance software, including commercially available packages and in-house proprietary codes. This makes an objective assessment of comparable IGCC plant designs, performance (and cost), and other perceived advantage claims (IGCC versus other technologies, too) very difficult, if not impossible. This paper develops a coherent simplified parametric model based on fully physics-based grounds to be used for quick design performance assessment of a large variety of IGCC power plants with and without CCS. Technology parameters are established from complex model runs and supplemented by extensive literature search. The model is tested using published data to establish its confidence interval and is satisfactory to carry conceptual design analysis at a high level to identify promising alternatives and development areas and assess the realism in competing claims.

Fuel-cooled thermal management, including endothermic cracking and reforming of hydrocarbon fuels, is an enabling technology for advanced aero engines and offers potential for cycle improvements and pollutant emissions control. The principal engine operability issue that will affect this enabling hydrocarbon fuel cooling technology is coke formation and deposition. Furthermore, the extent to which the benefits of high heat sink cooling technology can be realized is directly related to our ability to suppress coke formation and deposition. The successful implementation of this enabling technology is, therefore, predicated on coke suppression. In situ continuous coke deposit removal by catalytic steam gasification is being developed and successfully demonstrated as a means for suppressing pyrolytic coke deposit in fuel-cooled thermal management systems for advanced aero engines. The objective of this research is to investigate the in situ continuous coke deposit removal by catalytic steam gasification for suppressing pyrolytic coke deposition using a single-tube reactor simulator under representative hypersonic operating conditions. A coke removal system removes coke deposit from the walls of a high temperature passage in which hydrocarbon fuel is present. The system includes a carbon-steam gasification catalyst and a water source. The carbon-steam gasification catalyst is applied to the walls of the high temperature passage. The water reacts with the coke deposit on the walls of the fuel passage side to remove the coke deposit from the walls by carbon-steam gasification in the presence of the carbon-steam gasification catalyst. Experimental data shows the in situ continuous coke deposit removal by catalytic steam gasification is able to reduce coke deposit rate by more than ten times.

A newly developed integrated gasification fuel cell (IGFC) hybrid system concept has been tested using the Hybrid Performance (Hyper) project hardware-based simulation facility at the U.S. Department of Energy, National Energy Technology Laboratory. The cathode-loop hardware facility, previously connected to the real-time fuel cell model, was integrated with a real-time model of a gasifier of solid (biomass and fossil) fuel. The fuel cells are operated at the compressor delivery pressure, and they are fueled by an updraft atmospheric gasifier, through the syngas conditioning train for tar removal and syngas compression. The system was brought to steady state; then several perturbations in open loop (variable speed) and closed loop (constant speed) were performed in order to characterize the IGFC behavior. Coupled experiments and computations have shown the feasibility of relatively fast control of the plant as well as a possible mitigation strategy to reduce the thermal stress on the fuel cells as a consequence of load variation and change in gasifier operating conditions. Results also provided an insight into the different features of variable versus constant speed operation of the gas turbine section.

This study examines the performance of a solid oxide fuel cell- (SOFC-) based integrated gasification power plant concept at the utility scale (>100 MW). The primary system concept evaluated was a pressurized ∼150 MW SOFC hybrid power system integrated with an entrained-flow, dry-fed, oxygen-blown, slagging coal gasifier and a combined cycle in the form of a gas turbine and an organic Rankine cycle (ORC) power generator. The analyzed concepts include carbon capture via oxy-combustion followed by water knockout and gas compression to pipeline-ready CO 2 sequestration conditions. The results of the study indicate that hybrid SOFC systems could achieve electric efficiencies approaching 66% [lower heating value (LHV)] when operating fueled by coal-derived clean syngas and without carbon dioxide capture. The system concept integrates SOFCs with the low-pressure turbine spool of a 50 MW Pratt & Whitney FT8-3 TwinPak gas turbine set and a scaled-up, water-cooled 20 MW version of the Pratt & Whitney (P&W) PureCycle ORC product line (approximately 260 kW). It was also found that a system efficiency performance of about 48% (LHV) is obtained when the system includes entrained-flow gasifier and carbon capture using oxygen combustion. In order to integrate the P&W FT8 into the SOFC system, the high-pressure turbine spool is removed which substantially lowers the FT8 capital cost and increases the expected life of the gas turbine engine. The impact of integrating an ORC bottoming cycle was found to be significant and can add as much as 8 percentage points of efficiency to the system. For sake of comparison, the performance of a higher temperature P&W ORC power system was also investigated. Use of a steam power cycle, in lieu of an ORC, could increase net plant efficiency by another 4%, however, operating costs are potentially much lower with ORCs than steam power cycles. Additionally, the use of cathode gas recycle is strongly relevant to efficiency performance when integrating with bottoming cycles. A parameter sensitivity analysis of the system revealed that SOFC power density is strongly influenced by design cell voltage, fuel utilization, and amount of anode recycle. To maximize the power output of the modified FT8, SOFC fuel utilization should be lower than 70%. Cathode side design parameters, such as pressure drop and temperature rise were observed to only mildly affect efficiency and power density.

Integrated gasification combined cycles (IGCCs) are considered the reference technology for high efficiency and low emission power generation from coal. In recent years, several theoretical and experimental studies in this field have been oriented toward capturing CO 2 from IGCCs through the integration of solid oxide fuel cells (SOFCs) for coal-syngas oxidation, investigating the so-called integrated gasification fuel cell cycles (IGFC). However, molten carbonate fuel cells (MCFCs) can also be a promising technology in IGFCs. After rather comprehensive research carried out by the authors on modeling and simulation of SOFC-based IGFC plants, an interesting IGFC cycle based on MCFC is assessed in this work, where plant layout is designed to exploit the capability of MCFCs of transferring CO 2 and O 2 from the oxidant side to the fuel side. Syngas produced in a high efficiency Shell gasifier is cleaned and mainly burned in a combustion turbine as in conventional IGCCs. Turbine flue gas, rich with oxygen and carbon dioxide, are then used as oxidant stream for the fuel cell at the cathode side, while the remaining clean syngas is oxidized at the anode side. In this way, the MCFC, while efficiently producing electricity, separates CO 2 from the gas turbine flue gas as in a post-combustion configuration; oxygen is also transported toward the anode side, oxidizing the remaining syngas as in an oxy-combustion mode. A CO 2 -rich stream is hence obtained at anode outlet, which can be cooled and compressed for long term storage. This configuration allows production of power from coal with high efficiency and low emission. In addition, as already highlighted in a previous study where a similar concept has been applied to natural gas-fired combined cycles, a limited fraction of the power output is generated by the fuel cell (the most expensive component), highlighting its potential also from an economic point of view. Detailed results are presented in terms of energy and material balances of the proposed cycle.

The application of solid oxide fuel cells (SOFC) in gasification-based power plants would represent a turning point in the power generation sector, allowing to considerably increase the electric efficiency of coal-fired power stations. Pollutant emissions would also be significantly reduced in integrated gasification fuel cell cycles (IGFC) considering the much lower emissions of conventional pollutants ( NO x , CO, SO x , and particulate matter) typical of fuel cell-based systems. In addition, SOFC-based IGFCs appear particularly suited to applications in power plants with CO 2 capture. This is evident by considering that SOFCs operate as air separators and partly oxidized fuel exiting the fuel cell does not contain nitrogen from air, such as in conventional oxyfuel processes. The aim of this paper is the thermodynamic analysis of a SOFC-based IGFC with CO 2 capture. In the assessed plant, syngas produced in a high efficiency Shell gasifier is used in SOFC modules after heat recovery and cleaning. Anode exhausts, still containing combustible species, are burned with oxygen produced in the air separation unit, also used to generate the oxygen needed in the gasifier; the product gas is cooled down in a heat recovery steam generator before water condensation and CO 2 compression. The plant layout is carefully designed to best exploit the heat generated in all the processes and, apart from the fuel cell exotic components, far from industrial state-of-the-art, are not included. Detailed energy and mass balances are presented for a better comprehension of the obtained results.

This paper proposes a new kind of multifunctional energy system (MES) using natural gas and coal to more efficiently and more economically produce methanol and power. Traditional chemical processes pursue high conversion ratios of chemical energy of fuels. The new MES focuses on the moderate conversion of the chemical energy of fuels. To do this, about 50% of the coal is partially gasified with pure oxygen and steam as oxidant, and then the unconverted residuals (char) and natural gas are utilized synthetically by char-fired reforming to generate syngas. The combustion of char drives the methane/steam-reforming reaction. Here, the reforming reaction is also moderately converted, and the reforming temperature is decreased 100 – 150 ° C compared with that of the conventional method. The carbon-rich syngas from the partial gasifier of coal and hydrogen-rich syngas from char-fired reformer are mixed together and converted into methanol at a proper conversion ratio (lower than that of the conventional chemical process). Finally, the unconverted syngas is used in a combined cycle as fuel for power generation. As a result, the total exergy efficiency of the new system is 55–60%. Comparing to individual systems, including the integrated gasification combined cycle and the natural gas-based methanol synthesis plants, this new system can generate 10–20% more electricity with the same quantity of fossil fuel input and methanol output. In addition, the possibility of reducing the size of gasifier, reformer, and methanol synthesis reactor may reduce investment costs accordingly. These results may provide a new way to use coal and natural gas more efficiently and economically.

A partial gasification combined cycle with C O 2 recovery is proposed in this paper. Partial gasification adopts cascade conversion of the composition of coal. Active composition of coal is simply gasified, while inactive composition, that is char, is burnt in a boiler. Oxy-fuel combustion of syngas produces only C O 2 and H 2 O , so the C O 2 can be separated through cooling the working fluid. This decreases the amount of energy consumption to separate C O 2 compared with conventional methods. The novel system integrates the above two key technologies by injecting steam from a steam turbine into the combustion chamber of a gas turbine to combine the Rankine cycle with the Brayton cycle. The thermal efficiency of this system will be higher based on the cascade utilization of energy level. Compared with the conventional integrated gasification combined cycle (IGCC), the compressor of the gas turbine, heat recovery steam generator (HRSG) and gasifier are substituted for a pump, reheater, and partial gasifier, so the system is simplified obviously. Furthermore, the novel system is investigated by means of energy-utilization diagram methodology and provides a simple analysis of their economic and environmental performance. As a result, the thermal efficiency of this system may be expected to be 45%, with C O 2 recovery of 41.2%, which is 1.5–3.5% higher than that of an IGCC system. At the same time, the total investment cost of the new system is about 16% lower than that of an IGCC. The comparison between the partial gasification technology and the IGCC technology is based on the two representative cases to identify the specific feature of the proposed system. The promising results obtained here with higher thermal efficiency, lower cost, and less environmental impact provide an attractive option for clean-coal utilization technology.

This paper presents the thermodynamic and cost analysis of a coal-based zero-atmospheric emissions electric power plant. The approach involves an oxygen-blown coal gasification unit. The resulting synthetic gas (syngas) is combusted with oxygen in a gas generator to produce the working fluid for the turbines. The combustion produces a gas mixture composed almost entirely of steam and carbon dioxide. These gases drive multiple turbines to produce electricity. The turbine discharge gases pass to a condenser where water is captured. A stream of carbon dioxide then results that can be used for enhanced oil recovery or for sequestration. The term zero emission steam technology is used to describe this technology. We present the analysis of a 400 MW electric power plant. The power plant has a net thermal efficiency of 39%. This efficiency is based on the lower heating value of the coal, and includes the energy necessary for coal gasification, air separation, and for carbon dioxide separation and sequestration. This paper also presents an analysis of the cost of electricity and the cost of conditioning carbon dioxide for sequestration. Electricity cost is compared for three different gasification processes (Texaco, Shell, and Koppers-Totzek) and two types of coals (Illinois 6 and Wyodak). COE ranges from 5.95 ¢ ∕ kW h to 6.15 ¢ ∕ kW h , indicating a 3.4% sensitivity to the gasification processes considered and the coal types used.

A co-production system based on Fischer-Tropsch (FT) synthesis reactor and gas turbine was simulated and analyzed. Syngas from entrained bed coal gasification was used as feedstock of the low-temperature slurry phase Fischer-Tropsch reactor. Raw synthetic liquid produced was fractioned and upgraded to diesel, gasoline, and liquid petrol gas (LPG). Tail gas composed of unconverted syngas and FT light components was fed to the gas turbine. Supplemental fuel (NG, or refinery mine gas) might be necessary, which was dependent on gas turbine capacity, expander through flow capacity, etc. FT yield information was important to the simulation of this co-production system. A correlation model based on Mobil’s two step pilot plant was applied. This model proposed triple chain-length-dependent chain growth factors and set up correlations among reaction temperatures with wax yield, methane yield, and C 2 – C 22 paraffin and olefin yields. Oxygenates in the hydrocarbon, water, and vapor phases were also correlated with methane yield. It was suitable for syngas, iron catalyst, and slurry bed. We can show the effect of temperature on the products’ selectivity and distribution. User models that can predict product yields and cooperate with other units were embedded into Aspen plus simulation. Performance prediction of syngas fired gas turbine was the other key of this system. The increase in mass flow through the turbine affects the match between compressor and turbine operating conditions. The calculation was carried out by GS software developed by Politecnico Di Milano and Princeton University. The simulated performance assumed that the expander operates under choked conditions and turbine inlet temperature equals the NG fired gas turbine. A “F” technology gas turbine was selected to generate power. Various cases were investigated to match the FT synthesis island, power island, and gasification island in co-production systems. Effects of CO 2 removal/LPG recovery, co-firing, and CH 4 content variation were studied. Simulation results indicated that more than 50% of input energy was converted to electricity and FT products. Total yield of gasoline, diesel, and LPG was 136 – 155 g ∕ N m 3 ( CO + H 2 ) . At coal feed of 21.9 kg ∕ s , net electricity exported to the grid was higher than 100 MW . Total production of diesel and gasoline (and LPG) was 118,000 t ( 134,000 t ) ∕ year . Under the economic analysis conditions assumed in this paper, the co-production system was economically feasible. The after tax profits can research 17 million euro. Payback times ranged from 6 to 7 years.

Hydrogen yield of conventional biomass gasification is limited by chemical equilibrium constraints. A novel technique that has the potential to enhance the hydrogen yield by integrating the gasification and absorption reactions has been suggested. The method involves gasification of biomass in presence of a C O 2 sorbent. Ethanol was used as the model biomass compound and CaO was the representative sorbent. Equilibrium modeling was used to determine the product gas composition and hydrogen yield. The analysis was done using ASPEN PLUS software (version 12.1) and the Gibbs energy minimization approach was followed. The effects of temperature, pressure, steam/ethanol ratio, and CaO/ethanol ratio on product yield were investigated. Three case studies were conducted to understand the effect of sorbent addition on the hydrogen yield. Thermodynamic studies showed that the use of sorbents has the potential to enhance the equilibrium hydrogen yield of conventional gasification by ∼ 19 % and reduce the equilibrium C O 2 content of product gas by 50.2%. It was also found that the thermodynamic efficiency of sorbent-enhanced gasification (72.1%) was higher than conventional gasification (62.9%). Sorbent-enhanced gasification is a promising technology with a potential to improve the yield and lower the cost of hydrogen production.

In the last several years, gasification has become an interesting option for biomass utilization because the produced gas can be used as a gaseous fuel in different applications or burned in a gas turbine for power generation with a high thermodynamic efficiency. In this paper, a technoeconomic analysis was carried out in order to evaluate performance and cost of biomass gasification systems integrated with two different types of plant, respectively, for hydrogen production and for power generation. An indirectly heated fluidized bed gasifier has been chosen for gas generation in both cases, and experimental data have been used to simulate the behavior of the gasifier. The hydrogen plant is characterized by the installation of a steam methane reformer and a shift reactor after the gas production and cleanup section; hydrogen is then purified in a pressure swing adsorption system. All these components have been modeled following typical operating conditions found in hydrogen plants. Simulations have been performed to optimize thermal interactions between the biomass gasification section and the gas processing. The power plant consists of a gas-steam combined cycle, with a three-pressure-levels bottoming cycle. A sensitivity analysis allowed to evaluate the economic convenience of the two plants as a function of the costs of the hydrogen and electrical energy.

This paper investigates the performance of a new power cycle, a so called evaporative biomass air turbine (EvGT-BAT) cycle with gasification for topping combustion. The process integrates an externally fired gas turbine (EFGT), an evaporative gas turbine (EvGT), and biomass gasification. Through such integration, the system may provide the potential for adapting features from different advanced solid-fuel-based power generation technologies, e.g., externally fired gas turbine, integrated gasification combined cycle (IGCC), and fluidized bed combustion, thus improving the system performance and reducing the technical difficulties. In the paper, the features of the EvGT-BAT cycle have been addressed. The thermal efficiencies for different integrations of the gasification for topping combustion and the heat recovery have been analyzed. By drying the biomass feedstock, the thermal efficiency of the EvGT-BAT cycle can be increased by more than three percentage points. The impact of the outlet air temperature of the high-temperature heat exchanger has also been studied in the present system. Finally, the size of the gasifier for topping combustion has been compared with the one in IGCC, which illustrates that the gasifier of the studied system can be much smaller compared to IGCC. The results of the study will be useful for the future engineering development of advanced solid fuel power generation technologies.

Biomass integrated gasification-gas turbine (BIG-GT) technology offers the opportunity for efficient and environmentally sound power generation from biomass fuels. Since biomass is “carbon-neutral” it can be used in power generation equipment without contributing to the “greenhouse effect” if it is grown sustainably. The Brazilian BIG-GT initiative is one of a number of initiatives world-wide aimed at demonstrating, and thereby establishing, biomass as an energy resource for power production. The goal of the Brazilian BIG-GT project is to confirm the commercial viability of producing electricity from wood through the use of biomass-fueled integrated gasification combined-cycle (BIG-GT) technology. To fulfil this goal a 32 MWe eucalyptus-fueled demonstration power plant will be built in Brazil on the basis of a design made by TPS Termiska Processer AB (TPS). The first two phases of the project, which included experimental and engineering studies and the basic engineering of the plant, were completed in 1997. The next phase of the project, the construction and commissioning of the plant, is the recipient of a U.S. $35 million grant from the Global Environmental Facility (GEF) of the United Nations Development Program (UNDP), in addition to financing from the World Bank (WB). The plant will be built in Bahia, north-eastern Brazil. The customer of the plant is a consortium, SER—Sistemas de Energia Renova´vel, comprising of CHESF (Companhia Hidro Ele´trica do Sa˜o Francisco), a federally owned electricity generation and distribution company, Electrobras (Centrais Ele´tricas Brasileiras), a holding company comprising of the main Brazilian companies from the electric generation and distribution sector, and Shell Brasil. Start-up of the plant is scheduled for the year 2000. The plant will be based on a TPS designed atmospheric-pressure gasification/gas cleaning process. The product gas will be fired in a modified GE LM 2500 gas turbine. The gasification and gas cleaning process is based on the use of a circulating fluidized bed gasifier, secondary stage catalytic tar cracker and conventional cold filter and wet scrubbing technology. The feedstock to the plant will be mainly eucalyptus wood from a dedicated plantation which is harvested on a three-year cycle. This paper describes the background of the project leading up to the technology selection, the technology that will be employed in the plant and the outline of the economics of this “first-of-a-kind” plant. The progress made in establishing the organization and the formal framework (e.g., securing the electricity and fuel contracts) are also reported. Future projections of likely technological improvements and cost reductions, and their effect on the overall economics of an N th plant, are presented.

Black liquor, the lignin-rich byproduct of kraft pulp production, is burned in boiler/steam turbine cogeneration systems at pulp mills today to provide heat and power for onsite use. Black liquor gasification technologies under development would enable this fuel to be used in gas turbines. This paper reports preliminary economics of 100 - MW e scale integrated black-liquor gasifier/combined cycles using alternative commercially proposed gasifier designs. The economics are based on detailed full-load performance modeling and on capital, operating and maintenance costs developed in collaboration with engineers at Bechtel Corporation and Stone & Webster Engineering. Comparisons with conventional boiler/steam turbine systems are included. [S0742-4795(00)00402-6]

Fuel gas cleanup processing significantly influences overall performance and cost of IGCC power generation. The raw fuel gas properties (heating value, sulfur content, alkali content, ammonia content, “tar” content, particulate content) and the fuel gas cleanup requirements (environmental and turbine protection) are key process parameters. Several IGCC power plant configurations and fuel gas cleanup technologies are being demonstrated or are under development. In this evaluation, air-blown, fluidized-bed gasification combined-cycle power plant thermal performance is estimated as a function of fuel type (coal and biomass fuels), extent of sulfur removal required, and the sulfur removal technique. Desulfurization in the fluid bed gasifier is combined with external hot fuel gas desulfurization, or, alternatively with conventional cold fuel gas desulfurization. The power plant simulations are built around the Siemens Westinghouse 501F combustion turbine in this evaluation. [S0742-4795(00)00502-0]