Ronald L. Schoff Parsons Corporation George Booras Electric Power Research Institute

Transcription

1 Pre-Investment of IGCC for CO 2 Capture with the Potential for Hydrogen Co-Production Gasification Technologies San Francisco, California - October 12-15, 2003 Michael D. Rutkowski, PE Parsons Corporation Michael.D.Rutkowski@Parsons.com Ronald L. Schoff Parsons Corporation Ronald.L.Schoff@Parsons.com Neville A. H. Holt Electric Power Research Institute Nholt@epri.com George Booras Electric Power Research Institute Gbooras@epri.com INTRODUCTION Traditionally, two approaches regarding the capture of carbon dioxide (CO 2 ) have been employed when studying Integrated Gasification Combined Cycle (IGCC) conceptual plant designs. The first is to design the plant without provisions for CO 2 capture, placing emphasis on producing power with a minimum cost and maximum efficiency. The second approach is to design a grass roots IGCC plant that incorporates CO 2 capture and compression. The results of each approach are then compared to determine the amount of CO 2 captured and the costs of avoided CO 2 emissions. A third method is to develop a plant design that initially operates without CO 2 capture and is then retrofitted to incorporate CO 2 removal, with potential cost savings in mind. This paper describes the impact on cost and efficiency for IGCC plants that are retrofitted for CO 2 capture at a later date. Heat and material balances were established and preliminary costs of production were estimated for four different plant configurations based on the ChevronTexaco (CVX) quench gasifier. Capital and Operations & Maintenance (O&M) costs were provided for each of the configurations. (Table 1 describes the plant configurations.) The following plant configurations were investigated: Case 1A - An operating IGCC plant (as a point of departure) Case 1B - The same IGCC plant retrofitted for CO 2 capture and compression. Case 2A - A new greenfield IGCC plant with pre-investment for future CO 2 capture. Case 2B - The same new IGCC plant, retrofitted for CO 2 capture and compression. Interestingly, by configuring an IGCC plant for CO 2 capture, it becomes apparent that the syngas will have been ideally prepared for production of hydrogen. A case was made for the utilization of small quantities of hydrogen from coal. Rather than dedicate the entire plant to hydrogen production, the cost of producing small incremental amounts of hydrogen was assessed. Baseline Plant Description This IGCC plant design is based on the CVX gasifier technology, which utilizes a pressurized entrained-flow, oxygen-blown gasification process to produce a medium heating value fuel gas. The plant configuration is based on the quench gasifier option operating at approximately 950 psig. Figure 1 is a block flow diagram of the plant. 1

2 Gasifier Acid Gas Removal Table 1 Plant Configurations 1A 1B 2A 2B Operating IGCC plant Dual Train CVX Quench Single Stage Selexol IGCC plant retrofitted for CO 2 capture Dual Train CVX Quench Two Stage Selexol New greenfield IGCC plant with pre-investment Dual Train CVX Quench Single Stage Selexol Pre-investment IGCC plant, retrofitted for CO 2 capture Dual Train CVX Quench Two Stage Selexol Gas Turbine Dual GE 7 FA Dual GE 7 FA Dual GE 7 FA Dual GE 7 FA Relative Performance Base Case Derated with CO 2 Capture Base Case Base Case with CO 2 Capture Power generation technology is based on selection of two General Electric 7FA gas turbines. This plant utilizes a combined cycle for combustion of the syngas from the gasifier to generate electric power. Humidification of the syngas and nitrogen dilution aids in minimizing formation of NO x during combustion in the gas turbine burner section. A Brayton cycle using air and combustion products as working fluid is used in conjunction with a conventional subcritical steam Rankine cycle. The two cycles are coupled by generation of steam in the heat recovery steam generator (HRSG), by feedwater heating in the HRSG, and by heat recovery from the IGCC process. The design goal was to maximize the syngas availability for power production. To reach the high syngas availability goal, a single spare gasification train through the syngas scrubber was provided with the two operating trains. The resulting plant produces a net output of 509 MW e at a net efficiency of 35.4 percent on an HHV basis. Performance is based on the properties of EPRI TAG Pittsburgh No. 8 coal. Overall performance for the entire plant is summarized in Table 2, which includes auxiliary power requirements. The operation of the combined cycle unit in conjunction with oxygen-blown IGCC technology is projected to result in very low levels of emissions of NO x, SO 2, and particulate (slag). The low level of SO 2 in the plant emissions is achieved by capture of the sulfur in the gas by the Selexol AGR process. The AGR process is designed to remove over 99 percent of the sulfur compounds in the fuel gas, down to a level of 15 ppm in the syngas. NO x emissions are limited to 15 ppm in the flue gas (normalized to 15 percent O 2 ) by the use of syngas humidification and nitrogen dilution. The removal of ammonia with process condensate prior to the low-temperature AGR process helps lower NO x levels as well. Selective catalytic reduction (SCR) further reduces emissions to the 5 ppm level (at 15 percent O 2 ) or lower if required. Particulate discharge to the atmosphere is limited to low values by the gas-washing effect of the syngas scrubber and the AGR absorber. 2

3 Figure 1 - Block Flow Diagram Baseline CVX Gasification Plant Table 2 - Plant Performance Summary Baseline CVX Plant POWER SUMMARY (Gross Power at Generator Terminals, kwe) Gas Turbine Power 394,000 Sweet Gas Expander Power 13,950 Steam Turbine 206,950 Total 614,900 TOTAL AUXILIARIES, kwe 105,620 Net Power, kwe Net Plant Efficiency, % HHV Net Heat Rate, Btu/kWh (HHV) CONSUMABLES As-Received Coal Feed, lb/h Thermal Input, kwt Gasifier Oxygen (95% pure), lb/hr Claus Plant Oxygen (95% pure), lb/h 509, , ,663 1,440, ,458 7,116 OPERATING PLANT RETROFITTED FOR CO 2 CAPTURE AND COMPRESSION For this case, it is assumed that the baseline IGCC plant has been operating for a number of years at full capacity and has suddenly been called upon to capture 90% of the carbon feed as CO 2. The approach to achieving this performance is to shut down the operating plant and make a number of retrofit modifications. 3

4 Retrofit Issues The IGCC plant would be operating and producing power at the rated capacity of the gasifier and gas turbine, fired on clean syngas. To remove 90 percent of the CO 2, it is necessary to retrofit the plant with water-gas-shift reactors, and switch to a predominantly hydrogen-rich syngas. Since the systems to support the gasifier and ASU are operating at maximum capacity and the gas turbine will receive approximately 3 percent less than its rated fuel input, the plant will operate in a derated mode. The following retrofit modifications will be made to the baseline IGCC: Add a parallel air compressor to the ASU since less air extraction is coming from the gas turbine compressor. Add an additional nitrogen boost compressor. Remove the COS hydrolysis reactor and the LP steam generator/gas cooler. Insert the two shift-reactors and intercoolers. Re-arrange the aftercoolers between the shift and the condensate heat exchanger. Expand the Selexol process to remove and capture CO 2. Add CO 2 compressors and driers. Retrofit the gas turbine to burn hydrogen-rich syngas. Leave the steam cycle AS IS; although there will be less steam available. Add a tail gas treating unit (TGTU) and incinerator to the rear of the Claus Plant. Description For this case, the baseline CVX IGCC plant is retrofitted for CO 2 capture. Figure 2 is a block flow diagram of the plant. Because of the shift reaction, the LHV of the syngas is reduced, and upon keeping the coal and oxygen flow the same as the baseline CVX case, the gas turbine operates in a derated mode. The additional equipment needed for CO 2 removal includes two stages of shift, a second stage of the Selexol unit for CO 2 capture, and CO 2 compression units. The quantity of steam produced is reduced only slightly, so the same steam turbine can be used. In this plant design, raw synthesis gas generated with a high-pressure CVX quench-type gasifier is catalytically water-gas-shifted in order to concentrate CO 2. Two stages of high temperature shift are required to capture a nominal 90 percent of the CO 2. The gas goes through a series of shifts, gas coolers, and cleanup processes, including two stages of high temperature shift, a carbon bed mercury removal system, and two stages of AGR plant. Slag captured by the syngas scrubber is recovered in a slag recovery unit. Regeneration gas from the first stage of the AGR plant is fed to a Claus plant, where elemental sulfur is recovered. CO 2, along with hydrogen sulfide (H 2 S), is removed from the cool, particulate-free fuel gas stream with Selexol solvent. The purpose of the Selexol unit is to preferentially remove H 2 S as a product stream and then to preferentially remove CO 2 as a separate product stream. This is achieved in the so-called double-stage or double-absorber Selexol unit. CO 2 removed with the Selexol process is dried and compressed to a supercritical condition for subsequent pipeline transport. 4

5 The resulting plant produces a net output of 425 MW e at a net efficiency of 29.5 percent on an HHV basis. Overall performance for the entire plant is summarized in Table 3, which includes auxiliary power requirements. IGCC PLANT WITH PRE-INVESTMENT FOR CO 2 CAPTURE For the case where pre-investment is included in the Baseline IGCC plant for future retrofit of CO 2 capture equipment, the plant is oversized and extra space is allocated for the retrofit equipment. Removal of 90% CO 2 will result in the plant operating less efficiently, and will require more coal throughput to maintain the rated gas turbine performance. Thus, the plant is oversized so that the future retrofit will not cause a derating of the turbine. For example, the coal handling and air separation plants are sized with extra capacity to meet the increased demand of the plant with CO 2 removal. Also, downstream vessels are oversized in anticipation of increased volumetric gas flow. This is reflected in the increased capital cost. Until the plant is retrofitted, it will be operated at a reduced syngas rate of production but at a full gas turbine load. The plant configuration and performance are identical to the baseline IGCC case, as shown in Figure 1 and Table 2. PRE-INVESTMENT IGCC PLANT, RETROFITTED FOR CO 2 CAPTURE AND COMPRESSION Retrofit Issues The IGCC plant with pre-investment would be operating and producing power at the rated capacity of the gasifier and gas turbine fired on clean syngas. Pre-investment was included in the planning and construction to minimize the impact of conversion to a CO 2 capture operating mode. To remove 90 percent of the CO 2, it is necessary to retrofit the plant to water-gas-shift reactors and switch to predominantly hydrogen-rich syngas. Since the IGCC plant was operating in a power-only mode operating at reduced syngas production, the additional coal feed and oxygen demand can be accommodated, and the gas turbine will have adequate syngas, albeit hydrogen-rich, to maintain its rated output. Retrofit modifications made to the pre-investment IGCC plant are essentially the same as those made to the baseline plant, but are less invasive due to the pre-planning, spooling in critical process areas, and use of oversized process equipment as needed. As such, the capital associated with retrofit is much lower. Description For this case, the CVX IGCC plant with pre-investment for CO 2 capture is retrofitted for CO 2 capture. The plant was originally oversized so that the future retrofit would not cause a derating of the gas turbine. Two stages of shift, the second stage of the Selexol unit, and CO 2 compression units are added. The quantity of steam produced is reduced only slightly, so the same steam turbine can be used. In this plant design, raw synthesis gas generated with a high-pressure CVX quench-type gasifier is water-gas-shifted over a catalyst in order to concentrate CO 2. A series of two high temperature shifts is required to capture a nominal 90 percent of the CO 2. 5

6 Figure 2 - Block Flow Diagram CVX Gasification Plant with CO 2 Capture Table 3 - Plant Performance Summary Baseline CVX Plant Retrofitted for CO 2 Capture POWER SUMMARY (Gross Power at Generator Terminals, kwe) Gas Turbine Power 374,480 Sweet Gas Expander Power 11,090 Steam Turbine 191,260 Total 576,830 TOTAL AUXILIARIES, kwe 152,200 Net Power, kwe Net Plant Efficiency, % HHV Net Heat Rate, Btu/kWh (HHV) CONSUMABLES As-Received Coal Feed, lb/h Thermal Input, kwt Gasifier Oxygen (95% pure), lb/h Claus Plant Oxygen (95% pure), lb/h 424, , ,663 1,440, ,458 4,858 CO 2, along with H 2 S, is removed from the cool, particulate-free fuel gas stream with Selexol solvent. The purpose of the Selexol unit is to preferentially remove H 2 S as a product stream and then to preferentially remove CO 2 as a separate product stream. This is achieved in the so-called double-stage or double-absorber Selexol unit. CO 2 removed with the Selexol process is dried and compressed to a supercritical condition for subsequent pipeline transport. 6

7 Power generation technology is based on selection of two gas turbines derived from the General Electric 7FA machine, modified to be fired on hydrogen-rich gas. The plant is configured with two operating gasifiers, including processes to progressively cool and clean the hydrogen-rich syngas, making it suitable for combustion in the gas turbines. The resulting plant produces a net output of 449 MW e at a net efficiency of 29.5 percent on an HHV basis. Overall performance for the entire plant is summarized in Table 4, which includes auxiliary power requirements. Table 4 Plant Performance Summary Pre-Investment Plant Retrofitted for CO 2 Capture POWER SUMMARY (Gross Power at Generator Terminals, kwe) Gas Turbine Power Sweet Gas Expander Power Steam Turbine Total 394,000 11, , ,470 TOTAL AUXILIARIES, kwe 158,620 Net Power, kwe Net Plant Efficiency, % HHV Net Heat Rate, Btu/kWh (HHV) CONSUMABLES As-Received Coal Feed, lb/h Thermal Input, kwt Gasifier Oxygen (95% pure), lb/h Claus Plant Oxygen (95% pure), lb/h PERFORMANCE AND COST SUMMARY 448, , ,950 1,519, ,624 5,123 Table 5 summarizes plant performance and cost estimates. Capital cost estimates were developed based on a combination of vendor-furnished cost data and Parsons cost estimating database and then converted to a unit value of $/kw. The capital costs at the total plant cost (TPC) level include equipment, materials, labor, indirect construction costs, engineering, and contingencies. Production, operation and maintenance, and fuel cost values were determined on a first-year basis and then converted to unit values of $/kw-year or $/MWh. The baseline plant in the first column is a dual train IGCC case without CO 2 removal. It was presumed that this plant would be an operating entity, and would then be modified to capture CO 2. Retrofit of this plant (indicated in column 2) entailed an additional $88.3 million in capital, while derating the plant performance. As such, the cost of electricity increased by 30%. The third and fourth columns present the performance and costs for a greenfield IGCC plant with pre-investment to accommodate a future requirement for CO 2 capture. The pre-investment plant is oversized to operate at the same performance level as the baseline plant, but because of the pre-investment capital, the cost of electricity is 3% higher than the original baseline plant. Ultimately, the pre-investment plant retrofitted for CO 2 capture continues to operate at the turbine-rated performance level and capture 90% of the CO 2. The retrofit of the pre-investment case entailed an additional $63.4 million in capital. As such, the cost of electricity increased by 22%. 7

8 Table 5 - Performance and Cost Summary for Pre-Investment IGCC for CO2 Capture Baseline CVX IGCC Plant Operating CVX IGCC Plant Retrofitted for CO 2 Capture Derated 90% Capture Pre-investment CVX IGCC Plant Oversized Dual Train Pre-investment CVX IGCC Plant Retrofitted for CO 2 Capture Dual Train 90% Capture Performance Coal Flow, lb/hr 370, , , ,950 Total Oxygen Flow, lb/hr 375, , , ,747 Gas Turbine Power, kw 394, , , ,000 Expander Power, kw 13,950 11,090 13,950 11,600 Steam Power, kw 206, , , ,870 Total, kw 614, , , ,470 Total Auxiliaries, kw 105, , , ,620 Net Power, kw 509, , , ,850 Efficiency, %HHV Heat Rate, Btu/kWh HHV 9,653 11,569 9,653 11,550 CO 2 Captured, lb/hr N/A 839,372 N/A 885,381 Cost Total Plant Cost, 1,000 $ $589,896 $678,196 $619,600 $682,953 Total Plant Cost, $/kw $1,158 $1,596 $1,217 $1,522 Delta Cost of Retrofit, 1,000 $ $88,300 $63,353 Fixed Operating $10,806 $11,560 $11,055 $11,586 Variable Operating $13,837 $14,878 $14,547 $15,173 $51,157 $51,144 $51,157 $53,947 COE, $/Mwh a) $45.74 $59.32 $47.09 $57.23 COE based on TPC plus owners costs annualized at a rate of 15% and a 90% capacity factor 8

9 INCREMENTAL HYDROGEN PRODUCTION FROM COAL Basic calculations have shown that the amount of hydrogen required to support a regional or distributed transportation market is a fraction of that which can be produced from a full-scale coal gasification plant. For example: 2 lb H 2 (102,000 Btu LHV) is about the same as 1 US gallon of gasoline equivalent. Assume 10 lb H 2 per fill up. For a Fuel Cell Hydrogen vehicle averaging 55 mpg(eq) and 12,000 miles/year: 436 lb H 2 /yr /vehicle 10,000 vehicles = 4.36 million lb H 2 /yr, which at 8,760 hrs/yr = 500 lb H 2 /hr Using the IGCC plant with CO 2 capture, each 7FA train has 31,670 lb H 2 /hr in the fuel going to the gas turbine. Hydrogen for 10,000 vehicles can be supplied by 500/31,670 or 1.6% of the single train fuel gas flow (0.8% of the full two train flow). A typical hydrogen fill up station is envisaged as 12 pumps with 30 fill ups/day or 360 fill ups/day at 10 lb/fill up = 150 lbs H 2 /hr. Putting this into perspective, 10,000 vehicles can be supported from 1 percent of the IGCC plant and 100,000 vehicles can be supported by 10 percent of the IGCC plant. The incremental cost of hydrogen co-production at 10 persent coal increase and below was determined from the IGCC plant with shifted syngas and CO 2 capture. CVX IGCC PLANT DESIGNED WITH CO 2 CAPTURE AND INCREMENTAL HYDROGEN COPRODUCTION The baseline 90 percent CO 2 removal case was modified to produce hydrogen from the additional shifted syngas resulting from a nominal 10 percent additional coal feed. The incremental coal feed increase of 10 percent was selected as an amount of coal that could be added to the overall feed and accommodated with the existing gasifier configuration. The amount of hydrogen produced from this increase would be approximately 24 MMscfd and would be an order of magnitude greater than the hydrogen needed to fuel 10,000 automobiles. Additionally, with the 10 percent coal feed increase as the base case, hydrogen production was adjusted for sensitivity to 5 percent, 2 percent, and 1 percent coal flow increase. In this plant design, as shown in Figure 3, raw synthesis gas generated with a high-pressure CVX quench-type gasifier is shifted over a catalyst in order to concentrate CO 2. Two stages of a hightemperature shift are required to capture a nominal 90 percent of the CO 2. The higher amount of CO 2, along with H 2 S, is removed from the cool, particulate-free fuel gas stream with Selexol solvent. This is achieved in the so-called double-stage or double-absorber Selexol unit. CO 2 removed with the Selexol process is dried and compressed to a supercritical condition for subsequent pipeline transport. Power generation technology is based on selection of two gas turbines derived from the General Electric 7FA machine. The plant is configured with two operating gasifiers including processes to progressively cool and clean the hydrogen-rich syngas, making it suitable for combustion in the gas turbines. 9

10 In addition to supplying fuel gas for the turbines, the gasifier throughput is increased by 11 percent to incrementally produce additional syngas for hydrogen production. At the exit of the Selexol absorber, the gas is split, and the incremental hydrogen-rich stream is sent to a pressure swing adsorption (PSA) unit for hydrogen purification. The PSA off-gas is duct-fired in the heat recovery steam generator (HRSG). The resulting plant produces a net output of 441 MW e and (23.8 MMscfd) hydrogen at a net plant efficiency of 26.1 percent on an HHV basis. Overall performance for the entire plant is summarized in Table 6, which includes auxiliary power requirements. Cost results are shown in Table 7, indicating the incremental cost of hydrogen produced as a coproduct with electricity and CO 2. Sensitivity to 5, 2 and 1 percent coal feed increase is also included. Figure 3 CVX IGCC Plant with CO 2 Capture and Hydrogen Co-Production 10

11 Table 6 - Plant Performance Summary CVX Plant with CO 2 Capture and H 2 POWER SUMMARY (Gross Power at Generator Terminals, kwe) Gas Turbine Power 394,000 Sweet Gas Expander Power 11,600 Steam Turbine 207,760 Total 613,360 TOTAL AUXILIARIES, kwe 172,390 Net Power, kwe Net Plant Efficiency, % HHV Net Heat Rate, Btu/kWh (HHV) Hydrogen Production, lb/h Effective Thermal Efficiency (ETE, %) 2 CONSUMABLES As-Received Coal Feed, lb/h Thermal Input 1, kwt Gasifier Oxygen (95% pure), lb/h Claus Plant Oxygen (95% pure), lb/h 440, ,064 5, ,456 1,688, ,871 5,691 1 HHV of as-fed Pittsburgh 5.18% moisture coal is 13,260 Btu/lb 2 ETE=(Net Power (kwe) + Thermal Value of Product H 2 (kw th ))/Thermal Input (kw th ) COMPARISON OF COSTS OF INCREMENTAL HYDROGEN WITH CONVENTIONAL HYDROGEN The incremental hydrogen costs shown in Table 7 are indicative of the costs that can be achieved for small amounts of co-produced hydrogen. In comparison, the cost of producing hydrogen from full-scale natural gas and coal plants using conventional processes and similar economic assumptions is in the same range. This is predominantly the result of having shared plant capital charges for the incremental cases, and lower capital charges attributed to economy of scale for the full-sized plants. Table 8 shows the range of comparative hydrogen costs. 11

12 Table 7 Incremental Hydrogen Costs from IGCC Plant with CO 2 Capture Baseline 90% CO2 Recovery Plant 10% of Coal Feed to Hydrogen Production 5% of Coal Feed to Hydrogen Production 2% of Coal Feed to Hydrogen Production 1% of Coal Feed to Hydrogen Production Total Plant Costs, 1,000 $ $662,528 $681,912 $673,348 $667,655 $665,504 Owners Costs, 1,000 $ $129,091 $130,979 $130,145 $129,590 $129,381 Fixed O&M, $ $11,439,209 $11,578,138 $11,513,715 $11,470,890 11,454,709 Variable O&M, $ $14,984,074 $15,249,267 $15,188,694 $15,088,600 15,050,781 Fuel, $1.35/MMBtu HHV $53,947,442 $59,941,894 $56,940,633 $55,139,848 54,539,679 Total O&M, $/yr $80,370,725 $86,769,299 $83,643,042 $81,699,338 $81,045,169 Delta Total Plant Costs, 1,000 $ $19,384 $10,820 $5,127 $2,976 Delta Owners Costs, 1,000 $ $1,888 $1,054 $499 $290 Delta O&M, 1,000 $ $6,399 $3,272 $1,329 $674 Power Produced, MW e Cost of Power, $/MW e Delta Power Produced, MW e (7.88) (3.94) (1.58) (0.79) Delta Cost of Power, 1,000 $ ($2,485) ($1,243) ($497) ($249) Coal Flow, lb/h 390, , , , ,301 H 2 Product, lb/h 5,527 2,764 1, H 2 Product, million scf/d H 2 Cost w/o Gasifier Charge, cents/kscf a 154 (5.61) 161 (5.68) 171 (6.23) 181 (6.59) ($/MMBtu LHV) H 2 Cost with Gasifier Charge, cents/kscf b 190 (6.92) 196 (7.14) 206 (7.50) 216 (7.87) ($/MMBtu LHV) (a) The first cost of hydrogen is based on delta TPC and owners costs annualized at a rate of 15% and delta O&M assuming a 90% capacity factor. Since gasifier production is limited by the gas turbine syngas requirements, no charge was taken against the gasifier. (b) The second cost of hydrogen assumes a charge against the gasifier account proportional to the delta coal flow. Table 8 Comparative Costs of Hydrogen from Various Sources Hydrogen Source IGCC Plant with CO 2 Capture, 10% to 1% Incremental Natural Gas Steam Reforming, 150 MMSCFD Hydrogen $4.00/MMBtu HHV fuel cost Dedicated Coal Gasification Plant producing ~112 MMSCFD hydrogen from bituminous coal $1.35/MMBtu fuel cost Hydrogen Cost, cents/kscf ($/MMBtu LHV) cents/kscf ($ $7.87/MMBtu LHV) 225 cents/kscf ($8.20/MMBtu LHV) 211 cents/kscf ($7.69/MMBtu LHV) 12

13 CONCLUSIONS Effect of pre-investment on cost of electricity The decision to pre-invest an IGCC plant can be a business decision based on the probability of having a carbon sequestration requirement in the future. The pre-investment assessment has shown that with pre-investment, the plant has sufficient material handling capability and equipment spacing to readily be retrofitted for CO 2 capture in the future. This investment of about 5% more capital can be projected to increase the cost of electricity by about 3% without CO 2 capture, and by an additional 22% when retrofitted. Conversely, the cost of electricity increase resulting from CO 2 capture in a plant without pre-investment can be 30%. This is primarily due to the lower power output from the derated gas turbine. Range of hydrogen costs The incremental cost of hydrogen from IGCC plants has been shown to be competitive with hydrogen from full size coal plants. With minor process modifications, the syngas preparation in IGCC plants with CO 2 capture is ideally suited for hydrogen production. ACKNOWLEDGEMENTS The authors wish to acknowledge ChevronTexaco Worldwide Power and Gasification Inc.; General Electric Power Systems; Praxair, Inc.; and UOP LLC for their assistance in preparing the IGCC plant designs. 13