AppliedEnergy I0 (1982) 243 259
TO ELECTRICITY: INTEGRATED COMBINED CYCLE
J. C. CORMAN
Research and Development Center, iGeneral Electric Company, Schenectady, New York, 12345, USA
An adt'anced energy conversion system--the integrated gasification combined cycle ( IGCC) --has been ident([ied as an efficient and economical means o/com,erting coal to electricity Jor utility application. Several demonstration projects on a nearcommercial scale are approaching the construction stage. A coal com'ersionJacility has been constructed to simulate the operational features of a n IGCC. This process evaluation Jacility (PEF-scale) perJorms a dual function. (1) acquiring and processing data on the perJormance of the individual components--coal gasifier, gas clean up, and turbine simulator--that comprise the IGCC concept and (2) simulating the total system in an operational control mode that permits evaluation of system response to imposed load variations characteristic of utility operation. The results to date indicate that an efl~cient, economical IGCC can be designedso that the gas(fication/gas clean up plant and the power generation system operate compatibly to meet utilio, requirements in an em'ironmentally acceptable manner.
The integrated gasification combined cycle (IGCC) system has the potential to achieve efficient conversion of coal to electricity in an environmentally acceptable manner. The major components of this system are a gasifier which produces a coalderived gas, a clean up system which removes contaminants potentially harmful to the turbine and to the environment and an open cycle gas turbine combined cycle which uses the cleaned gas as fuel. This advanced energy conversion system has been identified as having the potential to be technically and economically feasible for utility applications, i Studies have been conducted to evaluate the competitive features of alternative energy conversion systems for the generation of electricity from coal 2-s and 243 Applied Energy 0306-2619/82/0010-0243/$02.75 ~ Applied Science Publishers Ltd, England, 1982 Printed in Great Britain
competitive alternative IGCC concepts. 6 - 8 In each study, an engineering approach was developed to compare the alternative concepts on a consistent basis with regard to both performance and ultimate cost of electricity. Detailed component and system performance calculations are carried out for each cycle configuration. A process flow schematic is developed, the components and subsystems are specified and component cost estimates are made. An estimate for construction costs is established on the basis of plant layout drawings. This data base makes it possible to calculate coal pile to bus bar efficiencies and the cost of electricity. By employing the capital cost and performance information presented in references 2 and 3, a consistent basis for comparison can be established for plant efficiency and cost of electricity. The results of this comparison are presented in Fig. 1 for the most attractive coal-to-electricity conversion systems, all of which offer potentially attractive alternatives to a steam plant with a first generation scrubber system. The IGCC concepts are shown to be competitive on both a performance and a cost basis with the promise of evolutionary improvements as the gas turbine inlet temperature is increased as new cooling concepts are introduced. 8
IGCC SYSTEM CHARACTERISTICS
The IGCC concept includes two major subsystems: fuel processing, comprising the gasifier and clean up components, and power generation, comprising the gas turbine/steam turbine combined cycle. The fuel processing subsystem gasifies coal in order to transform it into an energy form in which potential contaminants to the environment and to the power generation equipment can be removed effectively. The gaseous product of a coal-oxidant-steam reaction can be 'scrubbed' to remove those contaminants prior to combustion. All coal conversion processes include some steps that cause a loss of thermodynamic availability. As a result, the cleaned fuel has a lower total energy content than the coal supplied. The improved efficiency of the gas turbine/steam turbine combined cycle used for power generation compensates for the inefficiencies of fuel conversion to provide very attractive overall system performance. A simplified schematic diagram of an open cycle gas turbine/steam turbine combined cycle is shown in Fig. 2. In this concept a number of open cycle gas turbines are operated in parallel. The thermal energy in the exhaust from the turbines is utilised in a heat recovery steam generator (HRSG), and the steam is manifolded into a central steam turbine. With currently available equipment, each gas turbine would produce approximately 70 MW, with the steam bottoming plant producing approximately one-third of the total plant output. Several commercial installations of this type are in operation. One advantage of this cycle is that it has a very attractive conversion efficiency from fuel to electricity. Commercial combined cycle installations operate with
• IGCC;3000 F
POWER PLANT EFFICIENCY ( % )
• IGCC/2400 F
C C G T / 3 0 0 0 F/CDL
Convenhonal Boiler , Steam Cycle with Stack Gas Scrubber
Molten Carbonate Fuel Cell
M agnetohydr odynaml~:s
Integrated Gasification Combined Cycle
- Pressurized Fluidized Bed with Steam Cycle and Pressurized Gas Turbine
Atmospheric Flutdlzed Bed with Steam Cycle
Gas Turbine/Steam Turbqne Combined Cycle
Gas Turbine Inlet Temperature
2400 F &3000 F
Fig. 1. Cost of electricity versus power plant efficiency for coal-to-electricity conversion systems. (A mill is equal to one tenth of a US cent.)
~" --l r~
J . c . CORMAN LIQUID
I]I HEAT~ RECOVERY STEAM
AIR Fig. 2. Gas turbine/steam turbine combined cycle. power plant efficiencies as high as 42 per cent. The current requirement of the gas turbine for a clean petroleum liquid or natural gas fuel represents an operational drawback because these fuels are not likely to be available for large-scale electric generation in the future. (Policy set forth in the National Energy Act of 1978, as implemented in the Power Plant and Industrial Fuel Use Act, 1978). A second drawback is that the efficiency of the overall conversion process is directly dependent on the turbine inlet temperature, which is, in turn, limited by the materials and cooling schemes currently used for the hot gas path of the expansion turbine. Gasification and gas clean up fuel plants have the potential to overcome the first drawback by providing a coal-based fuel supply. The second drawback can be overcome by a new cooling concept for the gas turbines (i.e. water cooling), permitting significantly higher inlet temperatures which, in turn, will result in improved performance. 89 The increase in gas turbine firing temperature through improved hot gas path cooling techniques will allow a continuing evolution of improved IGCC performance. A schematic diagram of an IGCC system is shown in Fig. 3. The basic power generation components--open cycle gas turbine, heat recovery steam generator, and bottoming steam turbine--are similar to present-day commercially available equipment. However, a fuel processing subsystem is introduced to take coal as delivered to the plant site and produce a fuel which is acceptable to the gas turbine and also produce combustion by-products which are acceptable to the environment. The oxidant supply to the gasifier can be either air or oxygen. For either oxidant, integration of the functions of the fuel plant and power generation equipment improves the projected system performance. The air-blown IGCC system shown in Fig. 3 requires the more detailed integration since both oxidant and steam flows are coupled between the power generation subsystem and the fuel plant. In this
COAL TO ELECTRICITY: INTEGRATED GASIFICATION COMBINED CYCLE
PROCESS WATER OR STEAM
~ PARTICULATES, [ I L,-4
DRIVESTEAM [ IA PROCESSSTEAM . ICHEMICALr w ~, b ~ I CLEA"UP|
[CONDENSERI~ COOL WATERNG }
TO f | STACK
I/ RECOVERY sTEAM |l ~ENERATORSI'~"
' ~ I~ C O M : U S T O R ~ ~AR C
STEAM ' PROCESSSTEAM
WATER COOLING TOWERS
MULTIPLE GAS TURBINES Fig. 3. Integratedgasification combined cycle.
configuration, approximately one-sixth of the compressor discharge air is extracted from the gas turbine and delivered to the gasifier through a steam-driven boost compressor. Coal process steam and compressed air are reacted in the gasifier to form a gaseous fuel. Because air is used as the gasification oxidant, the gaseous fuel has a heating value of approximately 150 Btu/scf (about one-sixth that of natural gas). When the fuel gas exits from the gasifier, it still contains the same contaminants as the parent coal, although most of the coal ash is removed in the gasification process. The gas then goes through two clean up stages: the first, a physical clean up stager in which the contaminants potentially harmful to the gas turbine are removed by liquid scrubbing; the second, a chemical clean up stage in which the potential contaminants to the environment--sulphur and nitrogen compounds are removed from the gas stream. At that point, a clean gaseous fuel is available for gas turbine combustion. The processes are integrated in that compressed air is extracted from the gas turbine compressor for use in the gasifier, and steam is extracted from the steam turbine to drive the booster compressor and for use as process steam in the chemical clean up system. A number of studies have been performed to compare the performance of alternative I G C C systems utilising various gasifiers. 6"7' 1o These studies indicate that several of these systems are potentially competitive with conventional steam plants. There are three basic types of coal gasifier, although there can be many permutations and combinations of these. Each type is characterised by the way coal is brought into contact with the reactant gases (Fig. 4). In a fixed bed the flows of coal and reactant gases are countercurrent. In an entrained bed they are concurrent.
COAL ENTRAINED (COCURRENT)
(WELL - MIXED)
AIR ~ STEAM
J "~, ASH R
COAL FIXED - BED (COUNTERCURRENT)
Fig. 4. Basic gasification reactor types.
The fluidised bed acts as a well-stirred reactor with the coal being added either from the top or with the reactant gases. Each gasifier type has advantages and disadvantages as the fuel supply subsystem for steady-state operation of power generation systems. The fixed bed is most efficient in converting coal heating value into gas fuel heating value (i.e. making a rich gas), but it also produces liquid hydrocarbon as a by-product, which makes downstream gas clean up more difficult. The entrained bed does not produce liquids as a by-product, but a larger fraction of the coal heating value is converted to thermal energy, resulting in extremely high gas exit temperatures. The fluidised bed has uniform reactor temperature characteristics, but the coupling of reactant gas flows and bed dynamics places limits on the ability to operate at reduced load. These gasifiers have a few common characteristics when used in power generation system configurations. Each can be operated using air or oxygen and steam as reactants. In most arrangements, the gasifier pressure level is tied to that of the gas clean up system so that process gas volume flow rates are low and contaminant concentrations are high to improve cleaning effectiveness and reduce vessel volumes. The gasifier types also have unique characteristics that can have major effects on the way the system is controlled. The fixed bed and fluidised bed systems operate with high carbon inventories while the entrained bed has almost none. Therefore, very rapid load swings can be effected for short times in the fixed and fluidised bed
COAL TO ELECTRICITY: INTEGRATED GASIFICATION COMBINED CYCLE
systems by modulating gas flows only and affecting coal feed rate changes more slowly. In the entrained system, the reactant stoichiometry between coal, steam and oxidant must be precisely maintained. This requirement puts a burden on the control of the most difficult operation for any pressurised coal gasifier--coal feeding.
IGCC SIMULATION FACILITY
A need for technical understanding of the component and system performance of an IGCC system has led to the establishment of a process evaluation facility for IGCC simulation. 11 This PEF-scale facility has the capability to simulate the operational characteristics of a fuel plant/power generation system. In order to ensure that the PEF matched the characteristics of a commercial-scale system, its configuration was based on a full-scale IGCC system that was developed to a detailed design stage. 4'8 This facility simulates all the critical component features of the proposed full-scale system (Fig. 5). The PEF includes a fixed bed gasifier, a low-temperature gas clean up system, and gas turbine simulators. Auxiliary facilities include a high-pressure air supply system and steam boilers, as well as a computer data acquisition and control system that provides sophisticated data monitoring, analysis and control functions. This total system is currently operational (Fig. 6).
Gas!fieF The development activity has focused on an advanced air-blown, fixed bed gasifier. 1° A schematic diagram of the fixed bed gasifier is shown in Fig. 7. The advanced features of this system are the dual coal feed system with the lump coal fed through a lockhopper and the coal fines recycle tar mixture fed through an extruder, a top stirrer which can travel through the total shaft length and a rotating grate system which permits discharge of slightly clinkered ash. A fixed bed gasifier produces a liquid hydrocarbon by-product tar. A coal fines/tar extruder has been developed which extrudes a fines/tar mixture into the gasifier against the operational pressure, 4'8 thus permitting reintroduction of the hydrocarbons for further gasification. The stirrer in the top part of the reactor makes it possible to use highly swelling coals by breaking up any 'bridging' that occurs during devolatilisation. In order to keep the ash from fusing, a conventional fixed bed gasifier requires a large quantity of steam to be used as coolant in addition to the stream required for chemical reactions. In the advanced gasifier, a grate system permits the removal of slightly clinkered ash so that the reactor steam requirement is only approximately one-third that of the conventional fixed bed gasifier, i.e. 0.2 lbm steam/Ibm air, rather than 0.6 lbm/lbm.
CONCEPTUALFULL-SCALEIGCCSYSTEM COMPRESSOR GASTURBINE EXPANDER • |I FINE
~ . ~
HEATRECOVERY STEAM ~ GENE"tRATOR
~ ~~ I COMBUSTOR
I~ I BOOST ~,~J ~ COM PRESSOR
REHEAT, I RESATURATOR SULFUR
r~( E .~' J1FEEDWATER HEATER
I I I
[ T~SVSTEM I-PROCESSEVALUATIONFACILITYSIMULATION MAINCOMPRESSORS
[ Fig. 5.
Schematic of integrated gasification combined cycle processes. (Top) Conceptual full-scale IGCC system. (Bottom) Process evaluation facility simulation.
COAL TO ELECTRICITY: INTEGRATED GASIFICATION COMBINED CYCLE
Integrated gasification combined cycle--Process evaluation facility simulation.
Figure 8 shows the coal extruder which has been developed and operated on the experimental gasifier. The coal fines/tar extrudate is shown as a 6-in cylinder. This cylinder is chopped into smaller pieces as it is fed to the gasifier. The gasifier has been operational since 1976. The primary emphasis has been on the highly swelling eastern coals, and both Pittsburgh No. 8 and Illinois No. 6 coals have been successfully gasified at the 1 ton/h capacity of this reactor. This experimental gasifier, at 24 tons/day capacity, is approximately one-twentieth the size of the projected commercial gasifier. Most runs have been conducted at steamto-air ratios of 0.2 or less. The reduction in the steam required by the gasifier means a significant reduction in the water content of the raw gas (Fig. 9). As a result the steam/water carryover to the clean up system is reduced, simplifying the condensate handling system and allowing for the possibility of a zero water discharge IGCC plant design. Thus the reduced steam demand also increases the fuel gas, higher heating value (Fig. 10). The reduced steam demand also has implications for gasifier performance, as shown in Table 1. A comparative run at varying steam/air ratios indicates an 18 per cent improvement in enthalpy conversion with the reduced steam/air ratio.
J. (?. C O R M A N R-O M C O A L
COAL JI~ FINES
\'~ LUMP COAL STIRRER DRIVE
AUGER DRIVE ASSY
REQUIRES ONLY ~ 13 STEAM OF S-O-A GASIFIER STEAM & t
AIR IN GRATE ./. DRIVE ASSY
ASH Fig. 7.
Advanced fixed bed gasifier.
Extruder coal/tar feed system.
> z z o O IT"
I 100' PSIG [ 3 0 0 PSIG 0
CONDENSATE 61 o
I 1 0
STEAM / AIR ( I B M / LBM) F i g . 9.
in fuel gas.
STEAM = 1 720
ELAPSED TIME (MINUTES) Fig.
fuel gas heating
J . c . CORMAN TABLE 1 PERFORMANCEIMPROVEMENTWITHSTEAM High steam
0.67 0.575 2.67
0.25 0-600 2.26
Coal Air Steam
1.000 0.0473 0-166
1-000 0.0297 0.0520
0.131 (10.8 per cent decrease)
0.713 0.0952 0' 177 0.0711 0-0406 0.0216 0.0006 0-0459
0.756 0.0729 0"0426 0.0711 0.0330 0.0072 0.0003 0.0373
Measured total Unaccounted for
Steam/air ratio (Ibm/flows) Air rate (Ibm/s) Air/dry coal tteat Flows (HHV; Coal ==_1) Input
Gas~hemical --Sensible H20 Tar and oils Dust Residue Ash L-H loss Shell and CW
Cold Gas Efficiencies (HHV)
Coal basis Total reactant basis
(5-2 per cent increase) (18-6 per cent increase)
Gas clean up
The p r o d u c e r gas is cleaned o f c o n t a m i n a n t s at a low t e m p e r a t u r e ( a p p r o x i m a t e l y 200°F) in a direct c o n t a c t clean up system (Fig, 1 1). The two goals o f this clean up process are to p r o d u c e a fuel t h a t is a c c e p t a b l e to the gas turbine as well as a fuel that is a c c e p t a b l e to the e n v i r o n m e n t . This system consists o f a water q u e n c h / s c r u b which is directly c o u p l e d to the gasifier, a series o f heat exchangers, a n d an H2S r e m o v a l step. A r e h e a t / r e s a t u r a t i o n step is used to recover the t h e r m a l energy from the cool down process. The first goal is a c c o m p l i s h e d by achieving a significant reduction in the p a r t i c u l a t e a n d alkali metal c o n t e n t o f the gaseous fuel. A high energy venturi water scrub system is used to eliminate the p a r t i c u l a t e c o n t e n t (a potential t r a n s p o r t e r o f alkali), and the low t e m p e r a t u r e ensures t h a t alkali v a p o u r s are c o n d e n s e d and r e m o v e d in the liquid stream. The second g o a l - - - e n v i r o n m e n t a l a c c e p t a b i l i t y - - i s achieved by the removal o f sulphur a n d nitrogen c o m p o u n d s . The p r i m a r y sulphur c o m p o u n d , H2S, is
COAL TO ELECTRICITY: INTEGRATED GASIFICATIONCOMBINED CYCLE LOW-flTU
BLOW OOWN ~ _ WATt.
~.UOGE~ - J
~ ~'~TAR/IJQUOR / SEPARATOR
CLEAN LOW-BTU GAS
GAs o o o L E . J
TO TAR STEAM SYSTEM
ABSORBENT FLUID REGENERATOR
Fig. l 1. Coal gas clean up system.
removed from the gas stream in a direct contact chemical absorber. The sulphur capture system is a Benfield design. This absorption process ensures a low enough sulphur content to meet existing SO, standards, and further reductions are possible by adapting available processes. The primary nitrogen c o m p o u n d will be a m m o n i a , which is removed from the gas stream by the liquid wash and condensate processes and can be stripped from these liquid streams for disposal. Both the sulphur and the nitrogen can be discharged from the plant site in elemental or usable forms. N O x emissions from the 1GCC result from combustion of fuel-bound nitrogen c o m p o u n d s and by thermal production. The stoichiometric firing temperature for this fuel class will be sufficiently low to limit the thermal NOx generation to several parts per million. Therefore, N O , control can be achieved by removal o f the fuelb o u n d nitrogen, which is in the form o f a m m o n i a in the gas stream. The clean up system in th~ P E F facility operates on the full flow gas output from the gasifier. A s u m m a r y o f the clean up c o m p o n e n t design versus performance characteristics is shown in Table 2. The particulate removal is well within the design
TABLE 2 COAL GAS CLEAN UP SYSTEM P E R F O R M A N C E
Design Particulate scrubbing Alkali metal scrubbing Total sulphur removal -- H2S
-COS CO2 loss Hydrocarbon utilisation
30 ppm I per cent (max) > 8# ~0. l ppm 90 per cent 93 per cent 50 per cent 50 per cent 99 per cent (including CH4)
Experimental 3 5 ppm 99+ per cent < 1/~ ~0.02ppm 92 per cent 99 per cent 2(~30 per cent 20~55 per cent >90 per cent (condensible hydrocarbon)
specifications. The particulates remaining in the gas stream are in a size range ( < 1 ~) that eliminates concern for airfoil erosion. The alkali level (20 ppb) remaining in the gas as delivered to the turbine simulator was low enough to meet the gas turbine limit of 20 ppb in the combustion product which relates back to an allowable level of 100 ppb in the delivered gas. No potassium carry over from the absorbing column was noted. The total sulphur removal was within design specifications. The H2S capture was excellent at levels greater than 99 per cent in the Benfield column. If tighter control of sulphur was required, more emphasis would be placed on COS hydrolysis. The results on H2S/CO 2 selectively indicated that the CO 2 removal could be reduced below 50 per cent by optimising the system operating parameters. The light hydrocarbons were effectively reintroduced into the gas stream through resaturation employing the process condensate. Turbine simulator The gas from the fuel plant is introduced into a turbine simulator, shown schematically in Fig. 12, to evaluate the acceptability of coal-derived gas as a gas MAIN AIR FLOW FUELToMIZINGAIR _COMBUSTOR
/ ~EO~TZo E
Fig. 12. Turbinesimulator. turbine fuel. Two simulators were utilised: one at 10-12 atmospheres, 2000-2100 °F turbine inlet temperature and the other at 12-16 atmospheres, 2600-2800 °F turbine inlet temperature. Both turbine simulators operate on the total fuel gas flow from the gasifier/gas clean up fuel plant and achieve 8 pounds per second of combusted product flow through the sonic nozzle cascade, which simulates the first stage aerofoils on a gas turbine.
COAL TO ELECTRICITY: INTEGRATED GASIFICATION COMBINED CYCLE
After initial development of the coal gas combustor, no combustion problems occurred as a result of the normal + 10 per cent variation in gas heating value. During these investigations, the fuel gas water content was also varied from approximately 10 to 30 per cent with no resulting combustion problems after system optimisation. There was no evidence of induced dynamic oscillations between the fuel system and the turbine simulator. As would be expected from the gas composition shown in Table 2, no evidence of erosion, corrosion, or deposition of the hot gas path parts was noted. IGCC system simulation The three independent components--gasifier, gas clean up, and gas turbine combined cycle--must be operated successfully as an integrated system. A process evaluation facility (PEF) simulating the characteristics of the IGCC system and utilising the three experimental components has been designed to (1) establish the operational characteristics of an IGCC system, (2) evaluate and improve the integration features and (3) specify the appropriate control logic. The correspondence between a conceptual full-scale IGCC system and the PEF was shown in Fig. 5. In the PEF an independent compressor and an independent boiler supply the reactants to the gasifier and the oxidant to the combustor. This permits the operational transients expected with IGCC operation in a utility system to be imposed on the PEF simulation by computerised control of the compressor and boiler. This independence is an experimental advantage in that the flow stream transients that would occur in experimental-sized power generation equipment would not necessarily represent realistic IGCC operational characteristics. The decoupling of the flow streams from the power generation equipment makes it possible to impose transients on the PEF simulator that would be predicted from the analysis of the full-scale IGCC operation on a utility grid. The experimental fuel supply subsystem was coupled to the turbine simulator and the total IGCC PEF simulation placed under closed loop control. The variations in fuel gas flow required to maintain constant firing temperature in the turbine simulator (i.e. constant simulated output) could introduce variations in fuel system pressure. This potential system instability was countered by changing the gasifier steam/air blast to maintain fuel plant pressure within tolerable limits. In this closed loop operational mode, the turbine simulator was stabilised at a set point firing temperature. A controlled transient was introduced through a signal to simulate a loss of load demand. The firing temperature of the turbine simulator was reduced by 200°F over a 2-min time period. Under computer control, the fuel system tracked this transient and restabilised at the new set point with no adverse effects. The transient simulation is shown in Fig. 13. This brief transient experiment does not prove conclusively that IGCC systems can be dynamically controlled, but it does indicate stability of this fuel plant/turbine simulator system.
J . C . CORMAN
MASS SPEC HHV 1 0 - 2 4 0 BTUISCF) , / r ' ~
CONTROL TEMPERATURE ( 1200-2000°F )
ESSU E (2 0 - 3 6 0
L\ TEST TIME ( 2 MIN- DqV I
Simulated IGCC operation.
The IGCC system is potentially an extremely attractive coal-to-electricity conversion process. With minor modifications of state-of-the-art components, IGCC systems can be adapted to utility use. Programmes for advanced concept development are already in place that will result in higher generation efficiency and lower cost of electricity. The research and development approach has been to develop a simulation of an IGCC power generation concept at a PEF scale. This experimental facility is totally functional, with the gasifier, gas clean up and turbine simulator components operating in a closed loop computer-control mode. This facility has the capability to simulate the type of operation expected when an IGCC system is exposed to utility load cycles. The individual subsystems have operated in a manner compatible with the requirements imposed by this application. The gasifier has demonstrated an ability to handle a variety of coals and produce an acceptable quality of fuel gas. The gas clean up component has demonstrated an ability to remove 90 per cent of the sulphur from the fuel gas and to remove alkali metals and particulate from the gas stream prior to combustion. The turbine simulator has shown that this coal-derived fuel would be acceptable to current and future gas turbines. The PEF IGCC simulation will continue to be utilised to generate information for analytical simulation model verification and for establishing component and system conditions for demonstration plant operation.
COAL TO ELECTRICITY: INTEGRATED GASIFICATION COMBINED CYCLE
The chemical clean up system was constructed under a subcontract with General Electric Company's Gas Turbine Division, under a prime contract with the Department of Energy, Contract No. EX-76-C-01-1806, High Temperature Turbine Technology Program. Some of the information contained in this paper has previously been published in the 6th and 8th Energy Technology Conferences. It has been used here with permission of Government Institutes Inc., 966 Hungerford Drive, Rockville, Washington DC, 20850, USA.
REFERENCES I. J. C. CORMAN,Coal to electricity: Integrated gasification combined cycle, paper presented at Sixth Energy Technol. Conj,, Washington, DC, February 26~28, 1979. 2. J. C. CORUANand G. R. Fox, Performance and economics of advanced energy conversion systems for coal and coal-derived fuels, A S M E Paper, J. Eng. Power, 10 (April, 1978), p. 252. 3. B. D. POMEROVet al., Comparative study and evaluation of advanced cycle systems, General Electric Corporate Research and Development, EPRI AF-664, February 1978. 4. J. C. CORMAN et al., Energy com'ersion alternatives study, NASA-CR-134949 (3 Vols), General Electric Corporate Research and Development, Schenectady, NY, December, 1976. 5. Energy eom,ersion alternatives study, NASA-CR-134942 (2 Vols), Westinghouse Electric Corporation, Research Laboratories, Pittsburgh, Pa., November, 1976. 6. Economic studies of coal gasification combined cycle systems for electric power generation, Fluor. EPRI AF-642, January, 1978. 7. B. MCELMURRYand S. SMELSER,Economics of Texaco gasification-combined cycle systems, Fluor, EPRI AF-753, April, 1978. 8. A. CARUVANA, Development of high-temperature turbine subsystem technology to a technology readiness status, Phase I, Final Report, Contract EX-76-C-01-1806, General Electric Gas Turbine Division, Schenectady, NY, July, 1977. 9. A. CARUVANA,G. B. MANNING,W. H. DAY and R. C. SHELDON, Evaluation of a water-cooled gas turbine combined cycle plant, ASME 78-GT-77. 10. R. P. SHAH, D. J. AHNER, G. R. FOX and M. J. GLUCKMAN, Performance and cost characteristics of combined cycles integrated with second generation gasification systems, AS ME 80-GT-106. l 1. J. C. CORMAN,Integrated gasification combined cycle experimental simulation, paper presented at Eighth Energy Technol. Conf., Washington, DC, March 9 l 1, 1981.