Showing papers on "Integrated gasification combined cycle published in 2000"

Kinetic Modeling Study on the Potential of Staged Combustion in Gas Turbines for the Reduction of Nitrogen Oxide Emissions from Biomass IGCC Plants

Abstract: The potential for reduction of nitrogen oxides in gas turbine combustors was studied by detailed chemical kinetic modeling under ideal flow conditions. The investigation focused on turbines burning biomass-derived gasification gas from an air-blown integrated gasification combined cycle plant. The aim was to give detailed information about the parameters that favor reduction of NOx emissions, providing a solid background for designing an air-staged, low-NOx gas turbine. The potential and limitations of the detailed chemical kinetic modeling as a predictive tool for simulating the process were discussed. Instantaneous, delayed, and back-streamed air/fuel mixing models were tested to study the effect of mixing on the emissions. Predictions showed that the nitrogen chemistry was mainly affected by temperature and pressure: low temperatures of about 900−1000 °C and high pressures of about 10−20 bar favored fuel nitrogen conversion to N2. At atmospheric pressure, an increase in the number of air addition stag...

The ALSTOM benchmark challenge on gasifier control

Abstract: Integrated gasification combined cycle power plants are being developed around the world to provide environmentally clean and efficient power generation from coal. As part of the UK’s Clean Coal Power Generation Group, ALSTOM (formerly GEC ALSTHOM ) has undertaken a detailed feasibility study on the development of a small-scale prototype integrated plant (PIP), based on the air-blown gasification cycle. In pursuit of this goal the ALSTOM Power Technology Centre (formerly the GEC ALSTHOM Mechanical Engineering Centre) has produced a comprehensive dynamic model and control philosophy for the PIP. The gasifier is one component of the model which, being a highly coupled multi-variable system with five inputs (coal, limestone, air, steam and char extraction) and four outputs (pressure, temperature, bed mass and gas quality), has been found to be particularly difficult to control. For this reason the gasifier, together with its associated control specification, operating constraints and various disturbance characteristics, has been selected as the subject for this control challenge. This paper provides a brief background to the problem and describes the control specification and closed-loop tests to be performed.

Tar formation in pressurized fluidized bed air gasification of woody biomass

Abstract: The tars from an air-blown pressurized bubbling fluidized bed 90 kW (thermal) pilot biomass gasifier and also from an 18 MW IGCC demonstration plant were analyzed. The accuracy of the sampling method and its advantage/disadvantage was compared with other methods.

Desulfurization of hot syngas containing hydrogen chloride vapors using zinc titanate sorbents

Abstract: New coal gasification processes that can generate electricity with high thermal efficiency either in a combined gas-turbine, a steam-turbine cycle (IGCC), or in a fuel cell (MCFC) are being developed. Both of these new coal-to-electricity pathways require that the coal-derived fuel gas be at a high temperature and free of potential pollutants, such as sulfur compounds. Unfortunately, some high-sulfur Illinois coals also contain a significant amount of chlorine, which converts into hydrogen chloride (HCl) in the coal gas. In this study, two simulated gasifier-product streams were contacted with the zinc titanate desulfurization sorbent in a bench-scale atmospheric fluidized-bed reactor at temperatures ranging from 538 to 750 C (1,000--1,382 F). The first set of experiments involved treating a medium-Btu fuel gas (simulating that of a Texaco oxygen-blown, entrained-bed gasifier) containing 1.4% H{sub 2}S and HCl concentrations of 0, 200, and 1,500 ppmv. The second set of experiments evaluated the hot-gas desulfurization of a low-Btu fuel gas (simulating the product of the U-Gas air-blown gasifier), which had a 0.5% H{sub 2}S content and with HCl concentrations of 0, 200, and 800 ppmv. The results of the experiments at 538 and 650 C at all the HCl concentrations revealed no deleterious effects onmore » the capability of the sorbent to remove H{sub 2}S from the fuel-gas mixtures. In most cases, the presence of the HCl significantly enhanced the desulfurization reaction rate. Some zinc loss, however, was encountered in certain situations at 750 C when low-steam operating conditions were present. Also of interest, a portion of the incoming HCl was removed from the gas stream and was retained permanently by the sorbent.« less

Ecological Assessment of Integrated Bioenergy Systems using the Sustainable Process Index

Abstract: Biomass utilisation for energy production presently faces an uphill battle against fossil fuels. The use of biomass must offer additional benefits to compensate for higher prices: on the basis of a life cycle assessment (using BEAM to evaluate a variety of integrated bioenergy systems in connection with the Sustainable Process Index as a highly aggregated environmental pressure index) it is shown that integrated bioenergy systems are superior to fossil fuel systems in terms of environmental compatibility. The implementation of sustainability measures provides additional valuable information that might help in constructing and optimising integrated bioenergy systems. For a set of reference processes, among them fast pyrolysis, atmospheric gasification, integrated gasification combined cycle (IGCC), combustion and steam cycle (CS) and conventional hydrolysis, a detailed impact assessment is shown. Sensitivity analyses of the most important ecological parameters are calculated, giving an overview of the impacts of various stages in the total life cycle and showing ‘what really matters’. Much of the ecological impact of integrated bioenergy systems is induced by feedstock production. It is mainly the use of fossil fuels in cultivation, harvesting and transportation as well as the use of fertilisers in short-rotation coppice production that impose considerable ecological pressure. Concerning electricity generation the most problematic pressures are due to gaseous emissions, most notably the release of NOx. Moreover, a rather complicated process (high amount of grey energy) and the use of fossil pilot fuel (co-combustion) leads to a rather weak ecological performance in contrast to other 100% biomass-based systems.

Natural Gas Decarbonization to Reduce CO2 Emission From Combined Cycles: Part A — Partial Oxidation

Abstract: This paper discusses novel schemes of combined cycle, where natural gas is chemically treated to remove carbon, rather than being directly used as fuel. Carbon conversion to CO2 is achieved before gas turbine combustion. Therefore CO2 can be removed from fuel (rather than from exhausts, thus utilizing less demanding equipment) and made available for long-term storage, to avoid dispersion toward the atmosphere and the consequent contribution to the greenhouse effect.The strategy here proposed to achieve this goal is natural gas partial oxidation. The second part of the paper will address steam / methane reforming. Partial oxidation is an exothermic oxygen-poor combustion devoted to CO and H2 production. The reaction products are introduced in a multiple stage shift reactor converting CO to CO2. Carbon dioxide is removed by means of physical or chemical absorption processes and made available for storage, after compression and liquefaction. The resulting fuel mainly consists of hydrogen and nitrogen, thus gas turbine exhausts are virtually devoid of CO2.The paper discusses the selection of some important parameters necessary to obtain a sufficient level of conversion in the various reactors (temperature and pressure levels, methane-to-air or methane-to-steam ratios) and their impact on the plant integration and on the thermodynamic efficiency. Overall performance (efficiency, power output and carbon removal rate) is predicted by means of a computational tool developed by the authors. The results show that a net efficiency of 48.5%, with a 90% CO2 removal, can be obtained by combined cycles based on large heavy duty machines of the present technological status, either by using chemical or physical absorption.Copyright © 2000 by ASME

CO2 emission abatement from fossil fuel power plants by exhaust gas treatment

Abstract: In this paper thermodynamical and economic analyses of fossil-fuel-fired power plants, equipped with systems for CO2 recovery, are presented. The investigation has been developed with reference to power plants representative both of consolidated technology (i.e., steam cycle and combined cycle power plants), and of emerging or innovative technology (integrated coal gasification combined cycle, IGCC, and advanced mixed cycle, AMC). There are two main methods to reduce CO 2 from power plant flue gas: physical and chemical absorption. In this work chemical absorption and liquefaction of CO 2 removed have been considered. With reference to thermodynamical and economic performance, significant comparisons have been made between the above introduced reference plants. An efficiency decrease and an increase in the cost of electricity has been obtained when power plants are equipped with CO2 removal systems and units for liquefaction of the removed carbon dioxide. The main results of the performed investigation are quite variable among the different power plants here considered: their efficiency decreases in a range of 6 percentage points to nearly 13, while the electricity production cost increases in a range of 25% until 72%. The AMC stands out among the other power plants here analyzed because, after CO2 recovery, it exhibits the lowest net work output decrease, the highest net efficiency and the lowest final specific CO2 emission. In addition to this, its economic impact is favorable when the AMC is equipped with systems for CO2 recovery. As a result it achieves a net electric efficiency of about 50% with a carbon dioxide emission of about 0.04 kg/kWh, and the electricity production cost rises to about 25% in comparison with an AMC without CO2 removal and liquefaction systems. Copyright © 2003 by ASME.

PFB Air Gasification of Biomass, Investigation of Product Formation and Problematic Issues Related to Ammonia, Tar and Alkali

Abstract: Fluidised bed thermal gasification of biomass is an effective route that results in 100 % conversion of the fuel. In contrast to chemical, enzymatic or anaerobic methods of biomass treatment, the thermal conversion leaves no contaminated residue after the process. The product gas evolved within thermal conversion can be used in several applications such as: fuel for gas turbines, combustion engines and fuel cells, and raw material for production of chemicals and synthetic liquid fuels. This thesis treats a part of the experimental data from two different gasifiers: a 90 kWth pressurised fluidised bubbling bed gasifier at Lund University and a 18 MWth circulating fluidised bed gasifier integrated with gas turbine (IGCC) in Varnamo. A series of parallel and consecutive chemical reactions is involved in thermal gasification, giving origin to formation of a variety of products. These products can be classified within three major groups: gases, tars and oils, and char. The proportion of these categories of species in the final product is a matter of the gasifier design and the process parameters. The thesis addresses the technical and theoretical aspects of the biomass thermochemical conversion and presents a new approach in describing the gasification reactions. There is an evidence of fuel effect on the characteristics of the final products: a mixture of plastic waste (polyethylene) and biomass results in higher concentration of linear hydrocarbons in the gas than gasification of pure biomass. Mixing the biomass with textile waste (containing aromatic structure) results in a high degree of formation of aromatic compounds and light tars. Three topic questions within biomass gasification, namely: tars, NOx and alkali are discussed in the thesis. The experimental results show that gasification at high ER or high temperature decreases the total amount of the tars and simultaneously reduces the contents of the oxygenated and alkyl-substituted poly-aromatics in the product gas. There is an indication that the tars are the products of the stepwise destruction of the primary structure of the biomass. Increased temperature favours dissociation of the heavy tar compounds to lighter structures. During gasification a part of the fuel-bound nitrogen (fb-N) converts to ammonia which forms NOx in the following combustion steps of the product gas. The degree of conversion to ammonia is dependent on the process parameters and generally increases with increasing ER and temperature until a total carbon conversion is achieved. The mechanisms of the release of the fb-N and also the routes to minimise the ammonia in the product gas are discussed. In a gasification plant alkali metals can be the reason beyond problems such as agglomeration of the bed material, deposit formation on cold surfaces and erosion and corrosion of the ceramic and metallic parts. The experimental results show that the type of alkali from the fuel has a crucial importance in causing the alkali-related problems.

Effect of supplementary firing on the performance of an integrated gasification combined cycle power plant

Abstract: The effect of supplementary firing on the performance of an integrated gasification combined cycle (IGCC) power plant is studied. The results are presented with respect to a simple ‘unfired’ IGCC power plant with single pressure power generation for both the gas and the steam cycles as reference. The gases are assumed as real with variable specific heats. It is found that the most favourable benefit of supplementary firing can be obtained for a low temperature ratio RT only. For higher RT, only a gain in work output is possible with a reverse effect on the overall efficiency of the plant. The second law analysis reveals that the exergy loss in the heat-recovery steam generator is most significant as the amount of supplementary firing increases. It is also noteworthy that, although the total exergy loss of the plant decreases with higher supplementary firing for a low RT (= 3.0), the reverse is the case for a higher RT (= 6.0).

Operation Experiences of Siemens IGCC Gas Turbines Using Gasification Products From Coal and Refinery Residues

Abstract: The Integrated Gasification Combined Cycle concept is an emerging technology that enables an efficient and clean use of coal as well as residuals in power generation. After several years of development and demonstration operation, now the technology has reached the status for commercial operation. SIEMENS is engaged in 3 IGCC plants in Europe which are currently in operation. Each of these plants has specific characteristics leading to a wide range of experiences in development and operation of IGCC gas turbines fired with low to medium LHV syngases.The worlds first IGCC plant of commercial size at Buggenum/Netherlands (Demkolec) has already demonstrated that IGCC is a very efficient power generation technology for a great variety of coals and with a great potential for future commercial market penetration. The end of the demonstration period of the Buggenum IGCC plant and the start of its commercial operation has been dated on January 1, 1998. After optimisations during the demonstration period the gas turbine is running with good performance and high availability and has exceeded 18000 hours of operation on coal gas.The air-side fully integrated Buggenum plant, equipped with a Siemens V94.2 gas turbine, has been the first field test for the Siemens syngas combustion concept, which enables operation with very low NOx emission levels between 120–600 g/MWh NOx corresponding to 6–30 ppm(v) (15%O2) and less than 5 ppm(v) CO at baseload. During early commissioning the syngas nozzle has been recognised as the most important part with strong impact on combustion behaviour. Consequently the burner design has been adjusted to enable quick and easy changes of the important syngas nozzle. This design feature enables fast and efficient optimisations of the combustion performance and the possibility for easy adjustments to different syngases with a large variation in composition and LHV. During several test runs the gas turbine proved the required degree of flexibility and the capability to handle transient operation conditions during emergency cases.The fully air-side integrated IGCC plant at Puertollano/Spain (Elcogas), using the advanced Siemens V94.3 gas turbine (enhanced efficiency), is now running successfully on coal gas. The coal gas composition at this plant is similar to the Buggenum example. The emission performance is comparable to Buggenum with its very low emission levels. Currently the gas turbine is running for the requirements of final optimization runs of the gasifier unit.The third IGCC plant (ISAB) equipped with Siemens gas turbine technology is located at Priolo near Siracusa at Sicilly/Italy. Two Siemens V94.2K (modified compressor) gas turbines are part of this “air side non-integrated” IGCC plant. The feedstock of the gasification process is a refinery residue (asphalt). The LHV is almost twice compared to the Buggenum or Puertollano case. For operation with this gas, the coal gas burner design was adjusted and extensively tested. IGCC operation without air extraction has been made possible by modifying the compressor, giving enhanced surge margins. Commissioning on syngas for the first of the two gas turbines started in mid of August 1999 and was almost finished at the end of August 1999. The second machine followed at the end of October 1999. Since this both machines are released for operation on syngas up to baseload.Copyright © 2000 by ASME

Power Production with Zero Atmospheric Emissions for the 21st Century.

Abstract: This paper describes a new concept for economically producing power without atmospheric emissions of regulated or greenhouse gases. A 5-MW to 10-MW experimental electric power generating plant is being designed for installation at the Lawrence Livermore National Laboratory to perform research to develop the new technology and to demonstrate its reliability. The research electric power generating plant will burn any gaseous fuel, including syngas derived from coal, with oxygen. Natural gas and oxygen will be used initially to produce a mixture of steam and carbon dioxide. The mixture will be delivered to three turbines in series to produce electricity. After leaving the low-pressure turbine, the gaseous mixture will be cooled in a condenser where the carbon dioxide separates from the steam. The carbon dioxide will be pumped into a local oil formation, which is located at a depth of 460 m below ground adjacent to the Laboratory. In the more general siting case, the carbon dioxide would be pumped into deep underground permeable strata. The natural gas will be combusted with oxygen in a gas generator to produce the turbine working fluid. Three turbines will drive an electric generator to generate electricity. In the first phase of the research, the plant will use three commercially available steam turbines that operate at a temperature of 566 C. In a second phase, the high- and low-pressure turbines will be replaced by turbines using uncooled blade technology developed by the US Department of Energy (DOE) to permit a turbine operation temperature of 816 C. The intermediate turbine will use actively cooled gas turbine technology and operate at a temperature of 1,425 C. This plant will have an efficiency of 50%. DOE has funded research to reduce the cost of oxygen generation using ceramic membranes. When this technology becomes available and when high-temperature steam turbines are developed, efficiencies of 60% are expected, including the energy cost of carbon dioxide sequestration. Economic studies indicate that the cost penalty for sequestering the carbon dioxide of the research plant will be approximately 4%, when using the second-phase technology, making it one of the lowest-cost options for sequestration of greenhouse gases from a power plant. A similar cost penalty applies to plants with outputs ranging from 100 to 400 MW.

Natural Gas Decarbonization to Reduce CO2 Emission From Combined Cycles: Part B — Steam-Methane Reforming

Abstract: This paper discusses novel schemes of combined cycle, where natural gas is chemically treated to remove carbon, rather than being directly used as fuel. Carbon conversion to CO2 is achieved before gas turbine combustion. The first part of the paper discussed plant configurations based on natural gas partial oxidation to produce carbon monoxide, converted to carbon dioxide by shift reaction and therefore separated from the fuel gas. The second part will address methane reforming as a starting reaction to achieve the same goal. Plant configuration and performance differs from previous case because reforming is endothermic and requires high temperature heat and low operating pressure to obtain an elevated carbon conversion.The performance estimation shows that the reformer configuration has a lower efficiency and power output than the systems addressed in Part A. To improve the results, a reheat gas turbine can be used, with different characteristics from commercial machines. The thermodynamic efficiency of the systems of the two papers is compared by an exergetic analysis.The economic performance of natural gas fired power plants including CO2 sequestration are therefore addressed, finding a superiority of the partial oxidation system with chemical absorption. The additional cost of the kWh, due to the ability of CO2 capturing, can be estimated at about 13–14 mill$/kWh.Copyright © 2000 by ASME

Fuel Gas Cleanup Parameters in Air-Blown IGCC

Abstract: 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

Thermodynamic analysis of a partial gasification pressurized combustion and supercritical steam combined cycle

Abstract: The aim of this paper is to study the thermodynamic performance of a new combination of a partial gasification pressurized combustion gas cycle and a supercritical steam cycle as a means of advanced ‘clean coal’ power generation. Energy and exergy analyses of the proposed power cycle are presented. The effects of pressure ratio of the gas cycle, the turbine inlet temperature (TIT) and amount of coal gasification on the thermodynamic performance of the combined cycle are discussed. The optimum pressure ratio has to be determined on the basis of a judicious compromise between the net power and the overall efficiency. Overall efficiency is the maximum for an optimum TIT. The relative coal feeds for partial gasification and pressurized combustion may be adjusted with a compromise between net power and overall efficiency. The power output of the cycle can be increased by more coal gasification. However, this yields a lower overall efficiency.

Performance of a Biomass Integrated Gasification Combined Cycle CHP Plant Supplying Heat to a District Heating Network

Abstract: This paper examines a Biomass Integrated Gasification Combined Cycle (BIGCC) CHP plant using atmospheric air-blown gasification with wet cold gas clean-up and flue gas drying of the biomass feed stream. The plant provides heat and power to a medium sized municipality. The paper presents simulated performance results obtained using GateCycle software, and also presents results for the associated economy and CO2 emissions of the district heating system. The computed production costs of the cogenerated electricity are uncompetitively high, given current conditions in Sweden. In order to become competitive, international consensus must be reached on the level of economic advantage to be attributed to the “green” electric power produced by such a plant. However, likely price incentives for “green” power will probably be insufficient for BIGCC-CHP plants to become economically attractive. Therefore further effort is needed to improve the technology, reduce the investment costs, and identify options for longer annual operating times than those usually adopted for CHP plants coupled to district heating plants.Copyright © 2000 by ASME

Development of Low NOx Combustion Technology in Medium-Btu Fueled 1300 °C-Class Gas Turbine Combustor in IGCC

Abstract: The development of integrated coal gasification combined cycle (IGCC) systems ensures higher thermal efficiency and environmentally sound options for supplying future coal utilizing power generation needs. The Japanese government and electric power industries in Japan promoted research and development of an IGCC system using an air-blown entrained-flow coal gasifier. On the other hand, Europe and the United States are now developing the oxygen-blown IGCC demonstration plants.Gasified coal fuel produced in an oxygen-blown entrained-flow coal gasifier, has a calorific value of 8–13MJ/m3 which is only 1/5–1/3 that of natural gas. However, the flame temperature of medium-Btu gasified coal fuel is higher than that of natural gas and so NOx production from nitrogen fixation is expected to increase significantly. In the oxygen-blown IGCC, a surplus nitrogen produced in the air-separation unit (ASU) is premixed with gasified coal fuel (medium-Btu fuel) and injected into the combustor, to reduce thermal-NOx production and to recover the power used for the ASU. In this case, the power to compress nitrogen increases. Low NOx emission technology which is capable of decreasing the power to compress nitrogen is a significant advance in gas turbine development with an oxygen-blown IGCC system. Analyses confirmed that the thermal efficiency of the plant improved by approximately 0.3 percent (absolute) by means of nitrogen direct injection into the combustor, compared with a case where nitrogen is premixed with gasified coal fuel before injection into the combustor.In this study, based on the fundamental test results using a small diffusion burner and a model combustor, we designed the combustor in which the nitrogen injection nozzles arranged on the burner were combined with the lean combustion technique for low-NOx emission. In this way, we could reduce the high temperature region, where originated the thermal-NOx production, near the burner positively. And then, a combustor with a swirling nitrogen injection function used for a gas turbine, was designed and constructed, and its performance was evaluated under pressurized conditions of actual operations using a simulated gasified coal fuel. From the combustion test results, the thermal-NOx emission decreased under 11ppm (corrected at 16% O2), combustion efficiency was higher than 99.9% at any gas turbine load. Moreover, there was different effects of pressure on thermal-NOx emission in medium-Btu fuel fired combustor from the case of natural gas fired combustor.Copyright © 2000 by ASME

Bench-scale demonstration of hot-gas desulfurization technology

Abstract: The U.S. Department of Energy (DOE), Federal Energy Technology Center (FETC), is sponsoring research in advanced methods for controlling contaminants in hot coal gasifier gas (coal-derived fuel-gas) streams of integrated gasification combined-cycle (IGCC) power systems. The hot gas cleanup work seeks to eliminate the need for expensive heat recovery equipment, reduce efficiency losses due to quenching, and minimize wastewater treatment costs.

Integrated gasification combined cycle (IGCC) power plants

Abstract: In view of the paramount goal to reduce CO 2 emissions, use of the world's vast coal reserves and of increasing quantities of opportunity fuels such as refinery residues for environmentally benign power generation in plants with the highest possible efficiencies is a top priority. More than twenty IGCC power stations have already been built or are under construction worldwide with power output between 40 and 550 MW. This type of plant stands out due to its excellent performance in terms of efficiency and environmental impact and is therefore best suited to producing affordable and clean power with those dirty fuels. This contribution reports the growing operational experience gained in three of the large-scale European IGCC power stations which are all equipped with Siemens gas turbines: the Demkolec plant in Buggenum, Netherlands, is just in the third year of successful commercial operation, the Elcogas plant in Puertollano, Spain, is in the advanced commissioning phase on syngas, and also the ISAB plant in Priolo, Italy, has in the meantime begun operation on syngas. In the mid-term future, IGCC power plants will definitely achieve efficiencies of more than 50 % even when based on state-of-the-art power plant components and gas cleaning processes. Furthermore, it is of particular interest that gasification and gas cleaning act as an extremely effective filter for all the contaminants harmful to gas turbine blading and the environment. Polygeneration, i.e. simultaneously producing power and process heat as well as chemicals such as hydrogen, methanol and ammonia, is another important option unique to IGCC technology. The commercial breakthrough, however, is expected to be supported first by refinery-related applications where efficiency is not the key factor. Which position IGCC plants can ultimately achieve in the future liberalized electricity market, strongly depends on the extent to which the requirements of power producers can be met.

Optimized IGCC Cycles for Future Applications

Abstract: Use of gasification based on dirty fuels in markets other than syngas production for downstream chemical processes is emerging due to market changes associated with improved gas turbines, deregulation of electric power generation, as well as more and more stringent environmental regulations. Especially for the increasing quantities of opportunity fuels such as refinery residues, biomass and some grades of coal, integrated gasification combined cycle (IGCC) technology is best suited to producing affordable and clean power. In this contribution, all relevant aspects are discussed in the context of growing operational experience gained e.g. in the major European IGCC power stations: the Demkolec plant in Buggenum, Netherlands, is in the third year of successful commercial operation on syngas. The Elcogas plant in Puertollano, Spain, and the ISAB plant in Priolo, Italy, are also in syngas operation. Future IGCC plant designs and their significance for effectiveness, environmental and operational behavior and conservation of resources as well are the main focus of this paper. The results of cycle calculations are included to illustrate the above. Optimizing the bottoming cycle, for instance, is an effective means to improve IGCC concepts further. Polygeneration, i.e. simultaneously producing electrical power, district and process heat as well as chemicals such as hydrogen, ammonia, methanol and fertilizers, is another important process described here to meet today's requirements on modern power plant technologies. Moreover, topping an IGCC in the long term with solid oxide fuel cell equipment will achieve the highest overall efficiency of plants based on low-grade fossil fuels. IGCC stations must, of course, compete with all other power plant configurations. In particular, this includes supercritical pulverized-coal-fired steam power plants and the other so-called clean coal technologies, e.g. pressurized fluidized bed combustion. A comparison has been elaborated showing the outstanding performance of advanced IGCC concepts. Which position IGCC plants can ultimately achieve in the future liberalized electricity market, strongly depends on the extent to which the requirements of power producers in terms of capital investment, electricity generation costs, availability, relevant environmental regulations, site-specific conditions, field of application and disposal considerations can be met.

Comparative studies of advanced MHD topping power generation systems

Abstract: Efficiencies of four different types of MHD topping combined systems were compared where the topping units were the MHD generator and a thermochemical coal converter. The bottoming system was either combined gas and steam turbine units, a steam injection-type gas turbine, a steam turbine unit or a steam turbine coupled with a biomass unit. We also considered an IGCC system with conventional gasification schematics as a reference case. We showed that the system combined with the steam turbine and biomass units exhibited the highest efficiency of over 60% with presumably attainable MHD unit efficiencies although it is workable only under sunlight and its power scale may be limited by the pond area of the biomass plant. The present results emphasize capabilities of an advanced power generation system with extremely low environmental impacts and high efficiencies among those of the so far proposed fossil fuel-fired power plants on the basis of the MHD and the state-of-the-art heat recovery technologies.

Coal Conversion Processes, Gasification

Abstract: Coal gasification is a well-proven technology that provides an excellent way to utilize vast resources of coal efficiently and cleanly. The near-term application of coal gasification is in conjunction with combined cycle systems to generate electricity. Modern coal gasification processes produce high pressure syngas, which can be fed as fuel to a gas turbine. The high efficiency derived from combining gas turbine cycles with steam turbine cycles, along with significant environmental benefits, makes coal gasification combined cycle (CGCC) power plants more attractive than conventional technologies that generate power by coal combustion. Gasification technologies are described for various types of feedstocks. The chemistry of coal gasification is presented and process results are shown for several coals with a focus on gasifier performance and process efficiency. Other potential applications of coal involve the use of syngas chemistry to produce chemicals.

Application of bgl gasification of solid hydrocarbons for igcc power generation

Abstract: Since last year's GTC Conference, a considerable number of significant events have occurred in the gasification technology marketplace. New IGCC projects have come on stream with commercial operation, other new IGCC projects have been announced and started in development, environmental issues have gained emphasis, and energy prices, notably natural gas, have escalated dramatically. Directionally, all of these events appear to have created a more favorable atmosphere for IGCC projects. Related to an ongoing IGCC project currently in development, a joint analysis has been performed by Global Energy, General Electric Power Systems, and Praxair to evaluate technical and economic elements for the performance of BGL Gasification Technology based on solid hydrocarbon fuel feed to an IGCC for power generation. Results of the analysis provide a picture of the relative economics in today's environment for electrical power generation by conventional natural gas fired combined cycle power systems compared to using BGL Gasification Technology in an IGCC configuration.