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the project. The participants listed in Table 7-2 are the primary non-federal government companies, although each project had several supporting team members [4]. The projects are listed in Table 7-2 by four basic market sectors. A synopsis of the projects is provided in the following text, with an emphasis on emissions achievements.

Environmental Control Devices

The initial thrust of the CCT Program addressed acid rain, and 18 projects have been completed involving SO2 and NOZ control for coal-fired boilers. The technologies demonstrated provide a suite of cost-effective control options for the full range of boiler types. The projects included seven NOZ emission control systems installed on more than 1750 MW of utility generating capacity, five SO2 emission control systems installed on ~770 MW, and six combined SO2/NOZ emission control systems installed on more than 665 MW of capacity [4].

SO2 Control Technologies The CCT Program successfully demonstrated two sorbent injection systems, one spray dryer system, and two advanced flue gas desulfurization (AFGD) systems. Sulfur dioxide reductions varying from 50 to 90+% were demonstrated. AirPol, Inc., demonstrated that FLS milfo, Inc.'s gas suspension absorption system was an economic option for achieving Phase II 1990 Clean Air Act Amendments SO2 compliance in coal-fired boilers using high-sulfur coal [10]. The demonstration was performed using a vertical, single-nozzle reactor (i.e., spray dryer) with integrated sorbent particulate recycle in a 10 MW equivalent slipstream of flue gas from a Tennessee Valley Authority (West Paducah, Kentucky) 175 MW wall-fired boiler. Sulfur dioxide reductions of 60 to 90% were obtained firing 2.7 to 3.5% sulfur coal [4].

Bechtel Corporation demonstrated SO2 removal capabilities of in-duct confined zone dispersion (CZD)/flue gas desulfurization (FGD) technology— specifically, to define the optimum process operating parameters and to determine the operability, reliability, and cost-effectiveness of CZD/FGD during long-term testing and its impact on downstream operations and emissions [11]. The demonstration was performed using half of the flue gas from the Pennsylvania Electric Company Seward Station 147 MW tangentially fired boiler. Sulfur dioxide reductions of 50% were achieved firing 1.5 to 2.5% sulfur coal [4].

LIFAC-North America (a joint venture partnership between Tampella Power Corporation and ICF Kaiser Engineers, Inc.) demonstrated the LIFAC sorbent injection process, with furnace sorbent injection and sulfur capture occurring in a vertical activation reactor [12]. The LIFAC process was shown to be easily retrofitted to power plants with space limitations and burning high-sulfur coals. The 60 MW demonstration was performed on the Richmond (Indiana) Power & Light Whitewater Valley Station and achieved 70% SO2 removal firing 2.0 to 2.9% sulfur coal [4].

Pure Air on the Lake, L.P. (a subsidiary of Pure Air, which is a general partnership between Air Products and Chemicals, Inc., and Mitsubishi Heavy Industries America, Inc.) demonstrated Pure Air's AFGD process to reduce SO2 emissions by 95% or more at approximately one-half the cost of conventional scrubbing technology, to significantly reduce space requirements, and to create no new waste streams [13]. A single SO2 absorber that was built for Baily (Indiana) Generating Station Unit Nos. 7 and 8 (i.e., 528 MW) achieved 95% SO2 capture firing 2.3 to 4.7% sulfur coal [4].

Southern Company Services, Inc., demonstrated Chiyoda Corporation's Chiyoda Thoroughbred-121 AFGD process for combined particulate and SO2 capture with high reliability [14]. Testing performed at the Georgia Power Company Plant Yates, Unit No. 1 (100 MW), achieved over 90% SO2 removal efficiency at SO2 inlet concentrations of 1000 to 3000 ppm with >97% limestone utilization, 97.7 to 99.3% particulate removal, >95% HCl and HF capture, 80 to 98% capture of most metals, <50% capture of mercury and cadmium, and <70% capture of selenium [4].

NOx Control Technologies Under the CCT Program, seven NOX control technologies were assessed encompassing low-NOx burners (LNBs), advanced overfire air (AOFA), reburning, selective catalytic reduction (SCR), selective non-catalytic reduction (SNCR), and combinations of them.

NOz reductions varying from 37 to 80% were demonstrated. Southern Company Services, Inc., performed a demonstration using Foster Wheeler's LNB with AOFA and the Electric Power Research Institute's (EPRI's) Generic NOz Control Intelligent System (GNOCIS) computer software to achieve 50% NOZ reduction; to determine the contributions of AOFA and LNB to NOZ reduction and the parameters for optimal LNB/AOFA performance; and to assess the long-term effects of LNB, AOFA, combined LNB/AOFA, and the GNOCIS advanced digital controls on NOZ reduction, boiler performance, and auxiliary components [9,15]. The demonstration was performed on the Georgia Power Plant Hammond, Unit No. 4, which is a 500 MW wall-fired boiler, and achieved 68% NOZ reduction with fly ash loss-on-ignition (LOI) increasing from a baseline of 7 to 8-10% [4].

The Babcock & Wilcox Company (B&W) demonstrated the technical and economic feasibility of their coal reburning system to achieve greater than 50% NOZ reduction with no serious impact on cyclone combustor operation, boiler performance, or other emission streams [16]. The demonstration was performed on the Wisconsin Power and Light Company 100 MW Nelson Dewey Station, Unit No. 2, and achieved 52 to 62% NOZ reduction with 30% heat input from the coal [4]. B&W also demonstrated the cost-effective reduction of NOZ from a large, base-loaded, coal-fired utility boiler with their Low-NOZ Cell Burner (LNCB®) system to achieve at least 50% NOZ reduction without degradation of boiler performance at less cost than that of conventional low-NOz burners [17]. The demonstration was performed on the Dayton (Ohio) Power and Light Company 605 MW J.M. Stuart Plant, Unit No. 4, and achieved 48 to 58% NOZ reduction, experienced average CO emissions of 28 to 55 ppm, increased fly ash production without affecting the electrostatic precipitator (ESP) performance, and increased unburned carbon (UBC) losses by -28% [4].

The Energy and Environmental Research Corporation (EERC), currently GE Energy and Environmental Research, performed a demonstration to attain up to a 70% decrease in NOZ emissions from an existing wall-fired utility boiler firing low-sulfur coal using both natural gas reburning (GR) and LNBs, as well as to assess the impact of GR-LNB technology on boiler performance [18]. The demonstration was performed on a 172 MW wall-fired boiler (Public Service Company of Colorado Cherokee Station, Unit No. 3). It achieved 37 to 65% NOZ reduction, with 13 to 18% of the heat input coming from the natural gas; reduced SO2 and particulate loadings by the percentage heat input by natural gas reburning; and resulted in acceptable carbon-in-ash and CO levels with GR/LNB operation [4].

New York State Electric & Gas Corporation (NYSEG) demonstrated micronized coal reburning with the objective to achieve at least 50% NOZ reduction on a cyclone burner and 25 to 35% NOZ reduction on a tan-gentially fired boiler [19]. Demonstrations were performed on the NYSEG Milliken Station (Lansing, New York) Unit No. 1, which is a 148 MW tangentially-fired boiler, and Eastman Kodak Company's Kodak Park

(Rochester, New York) Power Plant Unit No. 1, which is a 60 MW cyclone boiler. Nitrogen oxide reductions of 59 and 28% were achieved in the cyclone- and tangentially fired units, respectively. The micronized coal consisted of 17 and 14% of heat input, respectively. LOI was maintained at <5% at Milliken Station but increased from baseline levels of 10-15 to 40-50% at Kodak Park [4].

Southern Company Services, Inc., evaluated the performance of eight SCR catalysts with different shapes and chemical compositions when applied to operating conditions found in U.S. pulverized coal-fired utility boilers firing U.S. high-sulfur coal under various operating conditions, while achieving as much as 80% NOx removal [20]. In this demonstration project, the SCR facility consisted of three 2.5 MW equivalent SCR reactors supplied by separate flue gas streams and six 0.20 MW equivalent reactors for a total of 8.7 MW equivalent using flue gas from the Gulf Power Company Plant Crist (Pensacola, Florida), Unit No. 4. The reactors were sized to produce data that will allow the SCR process to be scaled up to commercial size. Nitrogen oxide reductions of over 80% were achieved at an ammonia slip well under the 5 ppm level deemed acceptable for commercial operation [4].

Southern Company Services, Inc., also demonstrated short- and long-term NOx reduction capabilities of ABB Combustion Engineering Inc.'s (now Alstom Power, Inc.) Low-NOx Concentric Firing System (LNCFSTM) at various combinations of OFA and coal nozzle positioning [21]. The demonstration was performed on Gulf Power Company's 180 MW tangentially fired Plant Lansing Smith (Lynn Haven, Florida), Unit No. 2. Reductions in NOx of 37 to 45% were achieved [4].

Combined SO2/NOx Control Technologies Six combined SO2/NOx control technologies were assessed under the CCT Program. These technologies used various combinations of technologies and demonstrated NOx and SO2 reductions of 40-94 and 50-95%, respectively. ABB Environmental Systems demonstrated Haldor Topsoe's SNOXTM catalytic advanced flue gas cleanup system at an electric power plant using U.S. high-sulfur coals with the objective to remove 95% of the SO2 and more than 90% of the NOx from the flue gas, as well as produce a salable by-product of concentrated sulfuric acid [22]. In the SNOXTM process, particulate is removed using a high-efficiency baghouse, NOx is reduced in a catalytic reactor using ammonia, and SO2 is oxidized to SO3 in a second catalytic reactor and subsequently hydrolyzed to concentrated sulfuric acid. Testing performed in a 35 MW equivalent slipstream from the Ohio Edison Niles (Ohio) Station, Unit No. 2 (108 MW) achieved SO2 reductions in excess of 95% and NOx reductions averaging 94%, produced a sulfuric acid that exceeded federal specifications for a Class I acid, eliminated CO and hydrocarbon emissions due to the presence of the SO2 catalyst, and exhibited high capture efficiency of most air toxics (except for mercury) in the high-efficiency baghouse [4].

B&W demonstrated that their limestone injection multistage burner (LIMB) process can achieve up to 50% NOx and SO2 reductions and that Consolidated Coal Company's Coolside duct injection of lime sorbents can achieve removal of up to 70% SO2 [23]. The testing was performed at the Ohio Edison 105 MW Edgewater Station (Lorain, Ohio), Unit No. 4. The LIMB process reduces SO2 by injecting dry sorbent into the boiler above the burners—in this case, B&W's DRB-XCL® low-NOx burners; SO2 removal efficiencies varying from 45 to 60% with lime-based products and 22 to 40% with limestone were achieved, while nitrogen oxide reductions of 40 to 50% were obtained. The Coolside process, which is a humidified duct injection process, achieved 70% SO2 reduction [4].

B&W also demonstrated their SOx-NOx-Rox Box™ (SNRBTM) process with the objective of achieving greater than 70% SO2 removal and 90% or higher reduction in NOx emissions while maintaining particulate emissions below 0.03 lb/MM Btu [24]. The SNRBTM process combines the removal of SO2, NOx, and particulates in one unit: a high-temperature bag-house. Sulfur dioxide is removed using sorbent injection, NOx is reduced by injecting ammonia in the presence of an SCR catalyst inside the bags, and particulate is removed using high-temperature fiber filter bags. The testing was performed in a 5 MW equivalent slipstream from Ohio Edison Company's 156 MW R.E. Burger Plant (Dilles Bottom, Ohio), Unit No. 5, and SO2 and NO x reductions of 80-90 and 90%, respectively, were achieved. In addition, air toxic removal efficiency was comparable to that of the ESP at the plant, except that HCl and HF were reduced by 95 and 84%, respectively [4].

Energy and Environmental Research Corporation performed a demonstration in which natural gas reburning was combined with in-furnace sor-bent injection with the objective of reducing NOZ by 60% and SO2 by at least 50% in two different boiler configurations—tangentially and cyclone-fired units—while burning high-sulfur Midwestern coal [25]. Testing was performed on the Illinois Power Company 71 MW Hennepin Plant, Unit No. 1 (tangentially fired boiler), and on the City Water, Light and Power (Springfield, Illinois) 40 MW Lakeside Station, Unit No. 7 (cyclone-fired boiler). Nitrogen oxide reductions averaged 67 and 66%, respectively, for the tan-gentially and cyclone-fired boilers, while SO2 reductions averaged 53 and 58%, respectively [4].

New York State Electric & Gas Corporation performed a demonstration using Saarberg-Holter-Umwelttechnik (S-H-U), GmbH's formic acid-enhanced, wet limestone scrubber technology; ABB Combustion Engineering's LNCFSTM process; Stebbins Engineering and Manufacturing's split-module absorber; ABB Air Preheater's heat-pipe air preheater; and NYSEG's plant emissions optimization advisor (PEOA) with the objective of achieving high-sulfur capture efficiency and NOx and particulate control at minimum power requirements, zero wastewater discharge, and the production of by-products instead of wastes from the scrubber [26].

The flue gas from NYSEG's Milliken Station (Lansing, New York), Unit Nos. 1 and 2 (300 MW), was used in the project, and sulfur dioxide removals of 98 and 95% were demonstrated with and without formic acid, respectively, and 39% NOZ reduction was achieved [4].

Public Service Company of Colorado demonstrated the integration of five technologies—B&W's DRB-XCL® low-NOz burners with OFA, in-duct sorbent injection, flue gas humidification, and furnace (urea) injection— with the objective of achieving 70% reduction in NOZ and SO2 emissions and, more specifically, to assess the integration of a down-fired low-NOx burner with in-furnace urea injection and dry sorbent in-duct injection with humidification for SO2 removal [27]. Testing performed on the Public Service Company of Colorado Arapahoe Station (Denver, Colorado), 100 MW Unit No. 4, demonstrated 70% SO2 removal and 62 to 80% NOZ reduction [4].

Advanced Electric Power Generation Technology

The CCT Program provides a range of advanced electric power generation options for both repowering and new power generation in response to the need for load growth as well as environmental concerns. The emphasis of this program category included technologies that could effectively repower aging power plants faced with the need to both control emissions and respond to growing power demands. Repowering is an important option because existing power generation sites have significant value and warrant investment because the infrastructure is in place and siting new plants represents a major undertaking.

These advanced systems offer greater than 20% reductions in greenhouse gas emissions; SO2, NOZ, and particulate emissions far below New Source Performance Standards (NSPSs); and salable solid and liquid by-products [4]. Over 1800 MW of capacity are represented by 11 projects, including five fluidized-bed combustion systems (two completed, one ongoing, and two terminated in June 2003 after completing designs), four integrated gasification combined cycle systems (three completed and one ongoing), and two advanced combustion/heat engine systems (one completed and one delayed). The advanced electric power generation technology projects selected under the CCT Program are characterized by high thermal efficiency, very low pollutant emissions, reduced CO2 emissions, few solid waste problems, and enhanced economics. Five generic advanced electric power generation technologies are demonstrated in the CCT Program: fluidized-bed combustion, integrated gasification combined cycle, integrated gasification fuel cell, coal-fired diesel, and slagging combustion.

Fluidized-Bed Combustion City of Lakeland (Florida), Lakeland Electric was selected by the DOE for two CCT Program projects in 1989 and 1993; however, in 2003 these projects were terminated due to economic issues [9,28]. The first project, a pressurized circulating fluidized-bed (PCFB) project, was to demonstrate Foster Wheeler Corporation's PCFB technology coupled with Siemens Westinghouse's ceramic candle-type, hot-gas cleanup system and power generation technologies, which were to represent a cost-effective, high-efficiency, low-emissions means of adding generating capacity at greenfield sites or in repowering applications [4]. The second project, to be performed on the same boiler, was to demonstrate topped PCFB technology in a fully commercial power generation setting, thereby advancing the technology for future plants that will operate at higher gas turbine inlet temperatures and will be expected to achieve cycle efficiencies in excess of 45%.

JEA (formerly Jacksonville (Florida) Electric Authority) is demonstrating atmospheric circulating fluidized-bed (ACFB) combustion at a scale larger than previously operated. The objective of the project is to demonstrate ACFB combustion at 297.5 MW, which represents a scale up from previously constructed facilities; to verify expectations of the technology's economic, environmental, and technical performance; to provide potential users with the data necessary for evaluating a large-scale ACFB combustion as a commercial alternative; to accomplish greater than 90% SO2 removal; and to reduce NOZ emissions by 60% when compared with conventional technology [4]. The CFB boiler has operated at full load and achieved rated output and the demonstration test program has begun, but no published results are available [29].

The Ohio Power Company performed a pressurized fluidized-bed (bubbling) combustion (PFBC) demonstration to verify expectations of PFBC economic, environmental, and technical performance in a combined-cycle repowering application at utility scale; to accomplish greater than 90% SO2 removal; and to achieve an NOZ emission level of 0.3 lb/MM Btu at full load [30]. The demonstration was performed at the Ohio Power Company 70 MW Tidd Plant (Brilliant, Ohio), Unit No. 1, and was the first large-scale operational demonstration of PFBC in the United States. Sulfur dioxide removal efficiency of 90 to 95% was achieved at full load with calcium-to-sulfur (Ca/S) ratios of 1:1.4 and 1:5, respectively [4]. NOZ emissions were 0.15 to 0.33 lb/MM Btu, CO emissions were less than 0.01 lb/MM Btu, and partic-ulate emissions were less than 0.02 lb/MM Btu. Operationally, the PFBC boiler demonstrated commercial readiness.

Tri-State Generation and Transmission Association, Inc., demonstrated the feasibility of ACFB technology at the utility scale and evaluated the economic, environmental, and operational performance at that scale [31]. Three small, coal-fired stoker boilers at the Nucla Station (Nucla, Colorado) were replaced with a new 110 MW atmospheric CFB boiler. Environmentally, SO2 capture efficiencies of 70 and 95% were achieved at Ca/S ratios of 1.5 and 4.0, respectively; NOZ emissions averaged 0.18 lb/MM Btu; CO emissions ranged from 70 to 140 ppm; particulate emissions ranged from 0.0072 to 0.0125 lb/MM Btu (or 99.9% removal efficiency); and solid waste was essentially benign and showed potential as an agricultural solid amendment, soil/roadbed stabilizer, or landfill cap [4].

Integrated Gasification Combined Cycle The integrated gasification combined cycle (IGCC) process has four basic steps: (1) fuel gas is generated from a gasifier; (2) either the fuel gas is passed directly to a hot-gas cleanup system to remove particulates, sulfur, and nitrogen compounds or the gas is first cooled to produce steam and then cleaned conventionally; (3) the clean fuel gas is combusted in a gas turbine generator to produce electricity; and (4) the residual heat in the hot exhaust from the gas turbine generator is recovered in a heat-recovery steam generator, and the steam is used to produce additional electricity in a steam turbine generator. IGCC systems are among the cleanest and most efficient of the emerging clean coal technologies [4]. Sulfur, nitrogen compounds, and particulate matter are removed before the fuel is combusted (i.e., before combustion air is added), resulting in a much lower volume of gas to be treated in a post-combustion scrubber. With hotgas cleanup, IGGC systems have the potential for efficiencies of over 50%. An example of an IGCC system is shown in Figure 7-2 [32].

In a coal gasifier, the sulfur in the coal is released in the form of hydrogen sulfide (H2S) rather than SO2 as in a combustion process. Several commercial processes are capable of removing H2S; more than 99% of the H2S can be removed from the gas, making it as clean as natural gas. Energy conversion in fuels cells is more efficient than traditional energy conversion devices and can be as high as 60%. A typical fuel cell system using coal as a fuel includes a coal gasifier with a gas cleanup system, a fuel cell that uses the coal gas to generate electricity (direct current) and heat, an inverter to convert direct current to alternating current, and a heat recovery system that can be used to produce additional electric power in a bottoming steam cycle [4].

Fuel cells do not rely on combustion; instead, an electrochemical reaction generates electricity. Electrochemical reactions release the chemical energy that bonds atoms together—in this case, the atoms of hydrogen and oxygen [33]. The fuel cell is extremely clean and highly efficient. In a clean coal technology application, the fuel cell is fueled either by hydrogen extracted from the coal gas or a mixture of synthesis gas (low-Btu gas consisting of CO and H2). In a coal gasification/fuel cell application, coal gas is supplied to the anode, and air and CO2 are supplied to the cathode to produce electricity and heat. The principal waste product from the fuel cell is water.

Fuel cells are often categorized by the material used to separate the electrodes, which is termed the electrolyte. The most mature fuel cell concept is the phosphoric acid fuel cell [33]. Other concepts include the molten carbonate fuel cell (MCFC), which uses a hot mixture of lithium and potassium carbonate as the electrolyte, and the solid oxide fuel cell, which uses a hard ceramic material instead of a liquid electrolyte. The MCFC is integrated with one of the Clean Coal Technology IGCC projects described below.

Coal Handling and Slurry Preparation

Raw Syngas

Oxygen from Air Separation Plant

Coal Handling and Slurry Preparation

Raw Syngas

Oxygen from Air Separation Plant

Radiant Syngas Cooler

Burger Power Plant Ohio

Steam Turbine

FIGURE 7-2. Schematic diagram of an IGCC system. (From DOE, Clean Coal Technology, Tampa Electric Integrated Gasification Combined-Cycle Project: An Update, Office of Fossil Energy, U.S. Department of Energy, Washington, D.C., July 2000.)

Radiant Syngas Cooler

Steam Turbine

FIGURE 7-2. Schematic diagram of an IGCC system. (From DOE, Clean Coal Technology, Tampa Electric Integrated Gasification Combined-Cycle Project: An Update, Office of Fossil Energy, U.S. Department of Energy, Washington, D.C., July 2000.)

Electrical Current

Electrical Current

FIGURE 7-3. Schematic diagram of a molten carbonate fuel cell. (From DOE, Energy Efficiency and Renewable Energy—Hydrogen, Fuel Cells, and Infrastructure Technologies Program, U.S. Department of Energy, Washington, D.C., www.eere.energy.gov/hydrogenandfuelcells/fuelcells/types.html#mcfc. Last updated January 27, 2003.)

FIGURE 7-3. Schematic diagram of a molten carbonate fuel cell. (From DOE, Energy Efficiency and Renewable Energy—Hydrogen, Fuel Cells, and Infrastructure Technologies Program, U.S. Department of Energy, Washington, D.C., www.eere.energy.gov/hydrogenandfuelcells/fuelcells/types.html#mcfc. Last updated January 27, 2003.)

The MCFC evolved from work in the 1960s aimed at producing a fuel cell which would operate directly on coal [34]. While direct operation on coal seems less likely today, operation on coal-derived fuel gases is both technically and economically viable. The MCFC, shown schematically in Figure 7-3, uses a molten carbonate salt mixture as its electrolyte. The composition of the electrolyte varies but usually consists of lithium carbonate and potassium carbonate. At an operating temperature of about 1200°F, the salt mixture is liquid and a good ionic conductor. The MCFC reactions that occur are [34]:

Anode reactions: H2 + CO2- —> H2O + CO2 + 2e- (7-1)

The anode process involves a reaction between hydrogen and carbon monoxide and the carbonate ions from the electrolyte which produces water and carbon dioxide and releases electrons to the anode [34]. The cathode process combines oxygen and carbon dioxide from the oxidant stream with electrons from the cathode to produce carbonate ions that enter the electrolyte. The use of carbon dioxide in the oxidant stream requires a system for collecting carbon dioxide from the anode exhaust and mixing it with the cathode feed stream. Of the four IGCC projects, three have completed operations and one recently broke ground [4,9]. The project that broke ground on August 13, 2003, will incorporate an MCFC with a coal gasifier.

Tampa Electric Company demonstrated an advanced IGCC system using Texaco's (now ChevronTexaco) pressurized, oxygen-blown, entrained-flow gasifier technology [36]. The objective was to demonstrate IGCC technology in a greenfield commercial electric utility application at the 250 MW size using an entrained-flow, oxygen-blown gasifier with full heat recovery, conventional coal-gas cleanup, and an advanced gas turbine with nitrogen injection for power augmentation and NOz control [4]. The IGCC system shown in Figure 7-2 is that of the Polk system [32]. The demonstration was performed at the Tampa Electric Company Polk Power Station (Mulberry, Florida) and achieved greater than 98% sulfur capture, while NOz emissions were reduced by over 90% compared with a conventional pulverized coal-fired power plant, particulate matter was well below the regulatory limits set for the Polk plant site, and carbon burnout exceeded 95% [32]. The plant is currently in commercial operation.

Sierra Pacific Power Company tested IGCC using the KRW air-blown, pressurized fluidized-bed coal gasification system [37]. The objective was to demonstrate air-blown, pressurized fluidized-bed IGCC technology incorporating hot-gas cleanup; evaluate a low-Btu gas combustion turbine; and assess long-term reliability, availability, maintainability, and environmental performance at a scale sufficient to determine commercial potential. The emission targets were to remove more than 95% of the sulfur in the coal and emit less than 70% NOz and 20% less CO than in a comparable conventional coal-fired plant [4]. The 107 MW demonstration (shown in the block diagram in Figure 7-4), performed at the Sierra Pacific Power Company Tracy Station (Reno, Nevada), experienced many operational difficulties, and steady-state operation was not reached in the course of the testing; therefore, environmental performance could not be evaluated. The project did succeed in identifying and working through a number of problems, made possible only through a full-scale demonstration, and positioned the technology for commercialization. In addition, the testing proved the ability of the KRW gasifier to produce coal-derived synthesis gas of design quality [4].

The Wabash River Coal Gasification Repowering Project Joint Venture—a joint venture of Dynegy, Inc. (formerly Destec Energy, Inc.) and PSI Energy, Inc.—demonstrated IGCC using Global Energy's two-stage, pressurized, oxygen-blown, entrained-flow gasification system (i.e., E-Gas TechnologyTM) [39]. A schematic diagram of the system is shown in Figure 7-5. The objective was to demonstrate utility repowering with the E-Gas TechnologyTM, including advancements in the technology relevant to the use of high-sulfur bituminous coal, and to assess the long-term reliability, availability, and maintainability of the system in a commercial-scale unit [4]. The 296 MW demonstration was successfully performed at PSI Energy's Wabash River Generating Station (Terre Haute, Indiana) and achieved sulfur capture efficiency greater than 99%. The sulfur-based pollutants were

Coal and Limestone

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