1998 GASIFICATION TECHNOLOGIES CONFERENCE, SAN FRANCISCO/USA, 4-7 OCTOBER 1998 NEW DESIGN OF IGCC FOR COMPETITIVE POWER GENERATION G. Haupt and G. Zimmermann, Siemens AG Power Generation Group (KWU)/Germany H.-R. Baumann and N. Ullrich, Krupp Uhde GmbH/Germany R. Pruschek and G. Oeljeklaus, Universität-GH Essen/Germany ABSTRACT To provide the basis for clean and affordable energy in a competitive market is the reason why integrated gasification combined cycle (IGCC) technology is currently being developed further, while the existing IGCC prototype plants have the task of proving what is technically achievable. This contribution reports interim results of a comprehensive ongoing development potential study funded by the European Commission. First, the status of the advanced IGCC technology is described. This IGCC 98 concept, including what has been achieved in 1998, results in net station efficiencies around 52 % according to the site conditions prevailing in Denmark, where one of the world's most modern pulverized-coal-fired power plants (design efficiency 47 %) is currently under construction. The advanced IGCC station will be equipped with PRENFLO gasification developed by Krupp and a Siemens Model V94.3A gas turbinegenerator. Results of a detailed cost estimate based on Western European conditions and aimed at clearly lower specific capital investment for an IGCC power plant are depicted. This cost estimate is based mainly on bidding information from competent manufacturers and suggests that the target purchase price of US$ 1,100 per kw installed capacity is likely to be verified in the near future. One main factor contributing to achievement of this figure is the tremendous increase in net power output to about 450 MW with nearly the same absolute capital investment as for IGCC plants designed previously. Consequently, this permits IGCC generating costs surely lower than those of a comparable pulverized-coal-fired (PCF) steam power plant, so that the advanced IGCC stations described in this paper can be regarded as truly competitive. INTRODUCTION Preservation of resources and minimization of pollution are goals which today determine decisively further development of fossil-fuel-fired power stations. The most attractive features of the IGCC power plants are the extremely low environmental pollution and their capability to utilize "dirty fuels" such as coal, oil refinery residues, Orimulsion, biomass and waste, if the gasifiers are adequately adapted. Moreover, it is to be expected that such power stations will attain higher efficiencies than conventional PCF steam power plants, thereby also reducing CO 2 emissions effectively. This expectation is based on the fact that the natural-gas-fired combined cycle power plant already achieves an efficiency of 58 % at markedly lower investment compared to equivalent steam turbine power plants and the development potential is still not exhausted. The Puertollano station, starting point of most of the investigations carried out in this study, is designed for a net efficiency of 45 % (based on so-called standard i.e. low-ash bituminous 1
coal). Modern conventional PCF power plants attain approximately the same value, and ultrasupercritical steam cycles are supposed to achieve more than 50 % in the long term. Exploiting the potential advantages of IGCC technology is necessary to achieve and to demonstrate competitiveness with respect to conventional steam power plants, i.e. to increase the efficiency of IGCC stations above 50 % and to reduce costs. For that reason, the general objective of this study of potential for development is to improve the design of the IGCC power plant substantially, related to the IGCC plants already in operation in Europe (Buggenum, Puertollano) and in the US (Wabash River, Polk County, Piñon Pine). There are three factors determining electricity generating costs that can be influenced by process engineering and manufacturing, namely investment, fuel consumption and availability. If first-of-its-kind costs are neglected, it is to be expected that the specific investment of IGCC power plants will be close to those of conventional ones thereby achieving favourable economic electricity generation costs. In this case, the IGCC power plant will have a remarkable share of the power generation sector. STATUS OF THE IGCC 98 POWER PLANT IGCC technology must be measured against the most advanced PCF power stations. A plant of this type with a design efficiency of 47 % is currently being commissioned by ELSAMPROJEKT in Aalborg/Denmark (Nordjyllandsvaerket), on which the ambient conditions for this study are based (Tab. 1). The coal selected is Pittsburgh No. 8, a typical imported hard coal which can be readily gasified. With a target efficiency of considerably more than 50 %, it is assumed that the power plant will be operated primarily at base load. The plant is designed in a single train and has a capacity of roughly 450 MW, corresponding to the gas turbinegenerator used. The primary design objective is efficient operation with coal. Operation with natural gas as a secondary fuel, especially for start-up, plays only a secondary role with regard to efficiency. Ambient conditions Air temperature C 8.0 Air pressure bar 1.013 Relative humidity % 80.0 Condenser pressure bar 0.023 Proximate analysis Water wt% 5.50 Crucible coke wt% (dry) 60.85 Volatile matter wt% (dry) 39.15 Ultimate analysis C wt% (dry) 76.56 H 5.26 O 5.88 N 1.44 S (combustible) 3.00 Cl 0.06 Ash 7.80 Thermal properties Higher heating value (HHV) MJ/kg (dry) 32.613 Lower heating value (LHV) MJ/kg (dry) 31.438 Tab. 1: Design Data and Fuel Properties (Pittsburgh No. 8 coal) 2
Description of the Process Improvements Fig. 1 shows a simplified flowsheet of the IGCC 98 concept. The characteristic elements of IGCC technology are conversion of the primary fuel, e.g. coal, an open Brayton cycle (gas turbine) and a closed Rankine cycle (steam turbine), with various interactions. The results discussed in the following are mostly based on improvements achieved and published earlier in the course of this project [1]. Gasification Island and Heat Recovery from Syngas A prerequisite for efficient conversion of coal to gas is adequate preparation of the coal by milling and drying. Bowl mills are suitably using nitrogen for drying. The drying circuit is heated up to about 250 C by using IP steam and a small amount of natural gas. As a result of cost optimization, LP steam is not used for heating. The finished coal dust has a residual moisture content of about 1.2 % and is transported pneumatically under high pressure in dense phase flow with conveying vessels to the coal feed bin. In this way, a coal storage and lock hopper system is not necessary and the height of the gasification building can be reduced considerably. The so-called highly integrated IGCC concept leads to an increased operating pressure of the air separation unit (ASU). This high pressure of about 17 bar results in additional power requirement to separate oxygen and nitrogen with the aim to supply both streams dry and with high purity at high outlet pressures. An accordingly improved design of the ASU leads to a waste nitrogen stream in the range of about 30,000 m 3 STP/h, resulting in a reduced diluent nitrogen stream, after saturation with water, to the gas turbine. This measure will lead to mass flow conditions of the gas turbine near the design point and reduced capital investment of the gasification unit. A part of the waste nitrogen stream will be used for inertization of the coal drying loop with the result that nitrogen recovery items in the coal system are not necessary. In the PRENFLO gasifier, the coal is converted with oxygen (purity 95 % vol) and IP steam to a combustible gas. The PRENFLO gasifier forms an integrated system with the HP convection boiler, i.e. the two items of equipment have a common pressure container and are linked to each other functionally and structurally. The PRENFLO gasifier works at a pressure of 29 bar and a reaction temperature above the slag melting point. Almost 90 % of the ash is removed as slag. Only one slag sluicing line and one slag extractor are necessary for discharging the slag because of the relatively small total amount of slag (coal with 7.8 % ash). The gasifier consists of the gasification chamber as well as a quenching and cooling zone (integrated system gasifier/syngas cooler as mentioned above). Inside the gasifier, the fuel is converted to a syngas which mainly consists of carbon monoxide and hydrogen (approx. 93 % vol). The CO 2 content is lower than 1 % vol. Residence time of the gas is only a few seconds. Raw gas leaves the gasifier at a temperature of around 1,300 C at the top of the gasifier where it is quenched with recycled cold dedusted gas (quench gas) to a temperature of approx. 900 C before entering the cooling zone. The sensible heat of the raw gas which can be utilized corresponds to approx. 12 % of the introduced coal energy (LHV) and is mainly used for HP steam generation (7 %) and for reheating the clean syngas (3 %) in a raw gas/clean gas heat exchanger (RCHEX). About 2 % of the coal energy is used for the generation of IP steam. In the HP convection boiler, 3
HP steam with a pressure of about 180 bar is generated. In both heat exchangers, high heat flux densities can be achieved due to the high system pressure on the raw gas side and relatively high mean temperature differences which results in high heat flow. This leads to very compact and economic units. The raw gas leaves the HP evaporator with a temperature of 450 C leading to a clean gas temperature at the hot RCHEX end of 366 C. This results in a gas turbine fuel temperature of the mixture of saturated clean gas and saturated diluent nitrogen of 375 C, i.e. commercially available materials can be used for the control valves of the combustion chamber. Fly ash is removed in two steps, in a cyclone and in a candle filter. Coarse ash with a high carbon content removed in the cyclone is recycled to the gasifier and converted to environmentally acceptable slag. Fine fly ash enriched with heavy metals is separated in the candle filter and sluiced out of the system. The quench gas is recycled to the gasifier system at RCHEX outlet temperature of about 300 C. Using a wet dedusting system means that quench gas could be recycled with a temperature of about 155 C instead of 300 C, but the high pressure drop of the Venturi wash would lead to an about 200 kw higher power consumption of the quench gas compressor in spite of smaller quench gas flow according to the lower temperature. The upper part of Fig. 2 shows the corresponding syngas cooling curve. Using the dry dedusting system, an increase in net plant efficiency of 0.45 % points is achieved compared with the wet dedusting system. If lower quench temperatures are necessary, e.g. for other feedstocks, the efficiency gain is even higher (up to 1 % point). Capital investment and costs of electricity have been calculated for both configurations. The results show that for Pittsburgh No. 8 coal and West-European conditions, the dry dedusting system has also economic advantages compared with the wet dedusting system. Air-side and Nitrogen-side Integration Compared to previous concepts, the improved ASU design mentioned above results in a reduced diluent nitrogen stream to be admixed to the clean gas stream, as a small part of the N 2 fraction is used for cooling purposes inside ASU. The mass flow of the remaining diluent nitrogen stream, however, is sufficient to ensure balanced mass conditions in a highly integrated IGCC concept between compressor and turbine of a standard gas turbinegenerator usually designed for natural gas operation. Heat recovered from the hot air extracted downstream of the gas turbine compressor is supplied to the combined cycle by saturating and heating the diluent nitrogen and is equivalent to about 3.4 % of the coal input energy (LHV). As an example, hot air is cooled down from 414.8 C to 227.2 C by heating up the saturated diluent nitrogen stream from 129.1 C to 389.8 C. The energy of the hot air stream (19.1 MJ/s) is used for heating up the diluent nitrogen stream instead of, for example, boiler feed water. Energy required for saturating diluent nitrogen is supplied by low temperature heat (11.6 MJ/s) of the hot air by cooling this air stream from 227.2 C to 110.0 C. Saturator water used for heating the saturation circuit of diluent nitrogen is heated up from 95.0 C to about 180.0 C. In this manner, most of the hot air energy can be used very efficiently in the IGCC 98 process as depicted in the lower part of Fig. 2. 4
Combined Cycle Details of gas and steam turbine-generators as well as water/steam cycle have been previously described [1]. The salient data of the combined cycle are as follows: Gas turbine-generator Model V94.3A Steam turbine-generator HMN series - Live steam conditions 570 C/170 bar - Reheat conditions 570 C/39 bar Fuel Gas Temperature at Combustion Chamber Inlet There are typical reasons to examine level and feasibility of enhanced fuel gas temperatures at combustion chamber inlet for significance to IGCC concepts: Influence on overall plant efficiency strictly in view of NO x reduction measures to comply with a given limit Integration of a hot gas cleanup system Safety aspects as regards inflammability and autooxidation Parameter variations result only in a comparatively moderate rize of net plant efficiency with increasing fuel gas temperature, if internal losses due to the increasing degree of humidification as sole NO x reduction measure have been considered, because the increasing gas turbine power output is partly compensated by the reduced steam power output: 0.4 % points over the range of 250-550 C. Although the improved design of the IGCC 98 gas island, as described above, leads to a relatively moderate fuel gas temperature of 375 C, future concepts with temperatures above 400 C may be of greater interest, especially when hot gas cleanup is considered. To determine the maximum tolerable temperature from the safety point of view, ignition limits and autooxidation behaviour of the fuel gas have been investigated. One main parameter other than temperature and pressure is the oxygen content caused by admixing the N 2 fraction from the ASU which usually contains a small amount of oxygen, due ASU process conditions. IGCC-related ASU concepts are designed for relatively low O 2 contents, e.g. about 0.6 % vol in this study. Also part load operation or ASU failures, however, must not deteriorate the plant safety. As reliable self-ignition data for mixtures at higher pressure are not available in the literature, a test procedure has been developed and a test rig has been installed to investigate the ignition behaviour of two syngas mixtures between 250 and 500 C at 20 bar: one corresponding with this study, another one of higher H 2 content corresponding with syngas from refinery residues gasification. The content of admixed oxygen was in the range of 0.5-10 % vol. The experimental results were as follows: No self ignition is possible for both syngases below 7 % vol O 2 and below 500 C. Mean temperature rise of 15-125 C over the selected O 2 concentration range has been observed, indicating autooxidation effects which means, as a consequence, more or less decreasing fuel gas heating values. Humidification of the syngases has a moderating effect in terms of temperature rise, i.e. increasing system safety. 5
In terms of operational safety, no restrictions have to be deduced from these results when using diluent N 2 with O 2 concentrations below 3 % vol as is common practice with today's ASU in IGCC concepts. Moreover, the tendency to self ignition and autooxidation should decrease when changing from static test conditions to real turbulent flow conditions inside the plant. NO x Emissions Reduction The IGCC 98 concept clearly aims at a low NO x emissions level to emphasize the environmental advantage of IGCC power plants. Therefore, the target value for this study was fixed to about half of the present German legal limit (Tab. 2, GFAVO: German acronym based on "Großfeuerungsanlagenverordnung", i.e. large combustion facilities ordinance). NO x emissions limit mg/m 3 STP (6 % vol O 2, dry)ppm vol (15 % vol O 2, dry) CEC650127 GFAVO20039 IGCC 98 concept 103 20* ) * ) if a DENOX unit is used as described below Tab. 2: Comparison of Different NO x Emissions Limits Developing highly efficient gas turbine-generators is usually coupled with the realization of maximum possible turbine inlet temperatures. Catalytic combustion technology apart, which is not yet commercially available for heavy duty gas turbines, this means increasingly higher flame temperatures which cause extensive formation of NO x. Increased temperatures of the fuel gas fed to the gas turbine as a consequence of either increasing tendency toward fuel preheating or hot gas cleanup are enforcing this negative trend. In principle, various measures exist to lower the emissions of nitrogen oxides in IGCC concepts. Primary measures aim at preventing NO x formation by diluting the fuel gas, thus dampening temperature peaks which are the main cause of thermal NO x. Other than admixing diluent N 2, common methods for dilution include humidification with water or direct steam injection. Regarding the increasingly stringent limits and the above-mentioned gas turbine development, extensive humidification becomes more and more limited, both technically and economically, and may not suffice alone. In addition, large amounts of water for saturation lost with flue gas may not be acceptable or further reduction of the fuel gas heating value by dilution is not possible without causing problems in gas turbine operation. All these aspects provide arguments for NO x reduction in the flue gas stream, known as secondary measures. Such DENOX systems have been developed and are widespread, primarily for PCF steam power plants. But in the meantime, they are also being used in natural-gas-fired combined cycles. The IGCC 98 concept combines saturation of both clean gas and diluent nitrogen as well as a catalytic DENOX unit in the flue gas path (selective catalytic reduction, SCR, e.g. with SINO x catalysts developed by Siemens). The optimal degree of humidification is determined by the available sources of heat at low temperature level, which cannot be suitably exploited otherwise. Besides sensible heat of extracted air after preheating diluent nitrogen, the low temperature region of the flue gas in the HRSG can be taken into consideration. Heat of higher quality such as latent heat of LP or IP steam normally should not be used. Whether it is useful to saturate only clean gas after desulfurization and/or diluent N 2, separately or in 6
common apparatus after mixing, has to be decided from case to case for the specific conditions. The optimum reaction temperature range is 250-440 C. This temperature level requires the DENOX plant be arranged within the HRSG, avoiding the necessity of reheating flue gas. In case of a natural-gas-fired combined cycle, installation between HP and IP section proves expedient with respect to reaction temperature which should be held as constant as possible over a wide load range. This location (equivalent to about 360 C) has also been adopted for the IGCC 98 power plant. With clean gas and diluent N 2 saturation alone, as described above, NO x emissions at gas turbine outlet can already be reduced to about 60 ppm vol (15 % vol O 2, dry). The main parameter as regards power output and plant efficiency is the pressure drop caused by the DENOX unit. Increasing gas turbine back pressure accordingly reduces gas turbine power output in the present case by approx. 0.5 MW. Heat Recovery Steam Generator The previous concept [1] included common IP and HP drum systems of raw gas cooler and gas turbine HRSG. This would require both plant components be located close together and result in close link during operation. On the other hand, IP steam production by cooling the gasifier and the quench pipe are nearly offset by steam consumption in coal preparation and as gasifying agent, so that the gas island is nearly independent of the power block with respect to the IP water/steam system. As mass flow through IP evaporator of the HRSG is low and still assuming that natural gas is primarily intended for start-up and shutdown, the IP stage can be omitted resulting in a single pressure HRSG. The remaining small demand for IP steam for gasification purposes can be met with extraction steam as well. Therefore, IGCC 98 will include separate HP drum systems as usual which is in accord with the trend towards reduction of interfaces between gas island and power block in the interest of simplified plant operation. Because there is no LP steam generation in the HRSG as well, all LP steam required in the gas island is provided by extraction from the IP turbine section. Make-up water for both saturation systems is preheated in the low temperature section of the HRSG in a separate heat exchanger. Additional heat for saturating clean gas is also extracted in this manner. Based on the legal limit of 72 C (GFAVO) at the stack outlet, temperature of flue gas leaving the HRSG is adjusted to 75 C. Performance of the IGCC 98 Power Plant The findings of this development potential study can be summarized as follows: Power Output and Efficiency Tab. 3 gives an overview of significant plant data including overall efficiency. Approx. two thirds of auxiliary electric power requirement is accounted for by gas generation. Primary loads are the compressors for air separation unit products, particularly for the N 2 fraction. Main auxiliary loads in the combined cycle area are the main feedwater pumps. 7
Heat input (LHV): Coal (2545 tpd)874.9 MJ/s Natural gas (for coal preparation) 0.9 MJ/s Total875.8 MJ/s Gross power output: Gas turboset301.4 MW Steam turboset178.1 MW Total479.5 MW Gross efficiency (LHV) 54.7 % Power consumption: Gas island 17.8 MW Combined cycle 7.6 MW General facilities 1.5 MW Total 26.9 MW Net power output452.6 MW Net efficiency (LHV) 51.7 % Table 3: Salient Data Resulting from Overall Cycle Calculations A significant advantage also of the IGCC 98 concept is the ability to recover the sulfur in the coal as a pure salable byproduct. This sulfur content in the coal could be considered as an energy source when defining the thermal efficiency. Therefore, the heat content of the coal used could be corrected by the value of the sulfur fraction. The result would be a calculated net efficiency approx. 0.5 % points higher, i.e. 52.2 % for the IGCC concept under consideration. Emissions, Byproducts and Waste Materials The performance of the IGCC 98 concept includes a significant reduction of gaseous emissions and solid byproducts compared to today's most advanced PCF power plants, in particular compared to a standard PC boiler, based on the same coal: The emission of CO 2, mainly responsible for the anthropogenic greenhouse effect, is reduced by approx. 10 %, and even by approx. 25 % for standard PC boilers showing efficiencies in the range of 38-40 %. By both primary and secondary measures, i.e. dilution of clean syngas (admixing of diluent N 2 plus saturation with steam) and SCR, the NO x concentration for the IGCC 98 plant design can be kept at 20 ppm vol, equivalent to approx. 100 mg NO 2 /m³ STP (dry flue gas, 6 % vol O 2 ), which is only half of the GFAVO limit. With the desulfurization concept previously described [1], the SO 2 content of the IGCC 98 flue gas can easily be kept below 10 mg/m³ STP (dry, 6 % vol O 2 ) which is a tremendous reduction compared to usual SO 2 levels in flue gases from PCF power plants. The sulfur stream produced in IGCC plants without the need of any additive such as limestone amounts to approx. one fifth only of the corresponding gypsum stream produced in PCF power plants. The amount of the other residual material, i.e. slag, is also reduced similar to CO 2 due to the higher efficiency and therefore lower fuel consumption. 8
In general, this strategy of stepwise replacing existing PCF stations by advanced IGCC plants is still the most direct measure to reduce CO 2 emissions from power generation which neither needs an extra amount of primary fuel nor leaves a CO 2 utilization or disposal problem [3]. Costs A specific capital investment of US$ 1,100/kW results for the IGCC 98 power station from bidding information prepared by involved manufacturers. This reasonable price level could be achieved through the tremendous increase in net power output with nearly the same absolute capital investment as for IGCC plants designed previously. Fig. 3 shows the structure of this investment emphasising three representative blocks. Based on the IGCC 98 plant efficiency of 51.7 % determined in this study of potential for development, levelized electricity generating costs of e.g. 46 mills/kwh result, which are approx. 10 % less than with today's most advanced PCF steam power plants, if a fuel price of US$ 1.5/GJ (LHV) and 6,500 full-load hours/yr are assumed. In the future, the specific capital investment of IGCC plants optimized further could break the US$ 1000/kW barrier, e.g. by the following measures: Enhanced unit capacities, above all by using most advanced gas turbine-generators providing highest ratings. Decreased capital expenditure for overhead activities such as engineering and project management. Standardization of equipment and transition to series production. Rationalization measures for construction and installation. CONCLUSIONS AND FUTURE OUTLOOK The IGCC 98 concept is impressive because of outstanding efficiency and environmental compatibility. So, this process shows the second highest generation efficiency after future coal-based fuel cell power plants and fulfills all the demands made on progressive power plant options with regard to the emissions of CO 2, SO 2, NO x, dust, heavy metals, etc., as well as to the use of byproducts. Moreover, the IGCC 98 concept meets all the requirements in terms of profitability. The status of IGCC 98 power plants, however, does not represent the ceiling of technical and economic development at all [2]. Future investigations within this development potential study and beyond will for instance focus on: Further development of even more effective gas turbine-generators. Use of the achievements of advanced steam turbine-generators equipped with the socalled 3DV blading (3-dimensional, variable reaction). Further optimization of the fuel temperature at combustion chamber inlet. Selection and integration of a complete hot gas cleanup system, as soon as available. Transition to once-through HRSG (BENSON), i.e. generation of super-critical steam. Requisite plant components are expected to be available in the mid-term future. Implementation of these measures alone should result in considerable efficiency improvements of coal-based IGCC power stations and thus to another CO 2 emissions reduction of at least 5 %. 9
REFERENCES [1] Buskies, U., Ullrich, N., Baumann, H.-R., Haupt, G., Tränkenschuh, H.-Ch., Zimmermann, G., Pruschek, R. and Oeljeklaus, G.: IGCC - a Progressive and Profitable Power Plant Technology. POWER-GEN EUROPE '97. Conference Proceedings: Vol. III, pp. 295-310. Madrid/E, 17-19 June 1997. [2] Kloster, R., Oeljeklaus, G, Pruschek, R., Haupt, G. and Zimmermann, G.: Kohle- Kombikraftwerksprozesse - Schaltungsvarianten und Wirkungsgrade. VGB Conference: Forschung für die Kraftwerkstechnik 1998 (-VGB-TB 233 A-). Vol. "Posterbeiträge". Poster No. 6-5. Essen/D, 11-12 February 1998. [3] Göttlicher, G. and Pruschek, R.: Analysis of Development Potentials for Power Stations with CO 2 Removal/Concentration. 4th International Conference on Greenhouse Gas Control Technologies (GHGT-4). Paper Cap-09. Programme and Abstract Book, p. 22. Interlaken/CH, 30 August-2 September 1998. ACKNOWLEDGEMENT This study was carried out within the framework of the "European Community Research Programme" (JOULE III) with a financial contribution from the European Commission. 10
Fig. 1: Flowsheet of the IGCC 98 Power Plant Coal Fuel Gas IP Coal Preparation MDEA Air Claus Plant G Gas Turbine V94.3A Coal Feed Gasifier N 2 Raw Gas/ Clean Gas Heat Exchanger HP IP Raw Gas Clean Gas Candle Filter Cyclone COS Hydrolysis Clean Gas Sulfur Venturi Diluent N 2 Air Separation Unit Diluent N 2 Saturator Air HP DENOX (SCR) IP Saturation Water Preheat LP Exhaust Gas Reheat HP IP LP Steam Turbine Condenser G Make-up Water O 2 Slag IP Clean Gas Saturator Quench Waste Water Treatment O 2 N 2 Condensate Heat Recovery Steam Generator Flue Gas BFW Tank JOF3-CT95-0004 KWU TAP2/Zi 06.04.1998 ZI9897121914aE 11
Fig. 2: Cooling Curves of Raw Gas and Extraction Air Temperature [ C] 1200 1302.6 C 1000 800 900.0 C Raw Gas 600 400 HP Steam 450.0 C IP Steam 291.4 C 200 Clean Gas 112.9 C 0 0 20 40 60 80 100 120 Heat recovered [MJ/s] Raw Gas Cooling Temperature [ C] 400 414.8 C 300 Extraction Air 200 Diluent N 2 227.2 C 100 Saturator Cycle 110.0 C 0 0 5 10 15 20 25 30 35 Heat recovered [MJ/s] Extraction Air Cooling KWU TAP2/Ha/Zi 03.04.1998 ZI9804032E JOF3-CT95-0004 12
Fig. 3: Capital Investment Structure of the IGCC 98 Power Plant Power Generation & BOP* ) 48.8 % Gasification & Gas Treatment 42.6 % Air Separation & Coal Preparation 8.6 % Specific Capital Investment US$ 1,100/kW * ) BOP: Balance of Plant JOF3-CT95-0004 KWU TAP2/Ha/Zi 03.04.1998 ZI9804031E 13
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