7
Electric Power Generation

A major part of the DOE effort in the Office of FE is directed toward development of coal-fired electric power generation systems. The DOE program sponsors coal technology development from basic research through engineering, proof-of-concept testing, and commercial-scale demonstration. These efforts include R&D on components that are engineered and designed to operate in an integrated fashion in advanced power generation systems. For example, IGCC electric power systems include components such as advanced coal gasifiers, high-temperature gas cleanup systems, and advanced gas turbines.

This chapter focuses on the main coal-based electric power systems under development in DOE and industry programs—namely, pulverized coal-based systems, fluidized-bed combustion systems, and integrated gasification-based systems. Other concepts, including magnetohydrodynamics and direct coal-fired heat engines, also are discussed. In each case the main emphasis is on identifying technical issues, risks, and opportunities likely to influence future development activities by DOE and other organizations. Two key components of many of these systems—combustion turbines and emission control technologies—are then discussed separately. Complementing the R&D directed toward improvements in coal-based electric power systems, the DOE has engaged in extensive technology demonstration through its CCT program (see Chapters 2 and 8). Relevant CCT demonstration activities are also addressed in this chapter.

DOE's programs in coal-based power generation focus on advanced technologies that can enable utilities to meet future environmental requirements while containing electricity costs. Thus, advanced power systems must not only produce significantly lower emissions than current coal-fired plants but also must compete economically with other future options. Higher efficiencies in the new



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--> 7 Electric Power Generation A major part of the DOE effort in the Office of FE is directed toward development of coal-fired electric power generation systems. The DOE program sponsors coal technology development from basic research through engineering, proof-of-concept testing, and commercial-scale demonstration. These efforts include R&D on components that are engineered and designed to operate in an integrated fashion in advanced power generation systems. For example, IGCC electric power systems include components such as advanced coal gasifiers, high-temperature gas cleanup systems, and advanced gas turbines. This chapter focuses on the main coal-based electric power systems under development in DOE and industry programs—namely, pulverized coal-based systems, fluidized-bed combustion systems, and integrated gasification-based systems. Other concepts, including magnetohydrodynamics and direct coal-fired heat engines, also are discussed. In each case the main emphasis is on identifying technical issues, risks, and opportunities likely to influence future development activities by DOE and other organizations. Two key components of many of these systems—combustion turbines and emission control technologies—are then discussed separately. Complementing the R&D directed toward improvements in coal-based electric power systems, the DOE has engaged in extensive technology demonstration through its CCT program (see Chapters 2 and 8). Relevant CCT demonstration activities are also addressed in this chapter. DOE's programs in coal-based power generation focus on advanced technologies that can enable utilities to meet future environmental requirements while containing electricity costs. Thus, advanced power systems must not only produce significantly lower emissions than current coal-fired plants but also must compete economically with other future options. Higher efficiencies in the new

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--> technologies will contribute not only to lower fuel costs but also to improved environmental performance for a given power output. DOE's research goals for advanced power systems performance and cost were shown earlier in Table 2-3. Later sections of this chapter include discussions and assessments of goals for individual power generation technologies. Budget data are taken from the FY 1994 and FY 1995 congressional budget requests (DOE, 1993b, 1994d). The committee's comments on DOE's overall strategic objectives for advanced power systems are provided in Chapter 10. PULVERIZED COAL SYSTEMS Background Pulverized coal-fired electric power generation involves reducing coal size to a powder and conveying it with combustion air into a boiler where it is burned. The heat released evaporates water flowing in tubes in the boiler walls to form high-pressure, high-temperature steam, which is used to drive a turbine connected to an electric generator. The steam is then condensed back to a liquid and returned to the boiler to repeat the cycle (called the Rankine cycle). A wide range of coals may be combusted in pulverized coal boilers; however, units designed to burn a variety of coals are more costly than units using a more uniform fuel. Coal cleaning is widely practiced, usually at the mine, to reduce the coal ash and sulfur content and to raise its heating value, thus providing a more uniform fuel supply (see Chapter 5). Pulverized coal combustion has been practiced for many decades, and there is an extensive literature on boiler and system designs. State of the Art The overall efficiency of a pulverized coal power generation cycle is affected by many factors, including the thermodynamic cycle design, steam conditions (temperature and pressure), coal grind, combustion air-to-fuel ratio, fuel mixing, air leakage into the system, cooling (condenser) water temperature, and parasitic energy loads for auxiliary equipment such as grinding mills, pumps, fans, and environmental control systems. The net thermal efficiency (conversion of fuel energy to electricity leaving the plant) of U.S. coal-fired generating plants operating today averages 33 percent (EIA, 1993). However, newer state-of-the-art plants with full environmental controls have efficiencies of 38 to 42 percent, the higher values corresponding to new supercritical steam units operating in Europe (Gilbert/Commonwealth, Inc., 1992). Supercritical steam units operate at much higher temperature and pressure conditions than subcritical steam units, thus achieving higher overall efficiency. U.S. experience with early supercritical units installed in the 1960s and 1970s was generally unfavorable because of lack of operator experience and reliability and maintenance problems. Most U.S. coal

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--> plants today employ subcritical steam conditions, which give lower efficiency (typically 36 to 37 percent). Some early supercritical units, however, are still operating satisfactorily. The most efficient supercritical steam unit operating in the United States is the Marshall 4 unit of Duke Power, which was installed in 1970 with a design efficiency of 40 percent and today operates at a 38 percent efficiency without a FGD (flue gas desulfurization) unit (Electric Light and Power, 1993). Typical capital costs of modern U.S. subcritical pulverized coal plants equipped with an FGD system range from about $1,100 to $1,500/kW, with typical electricity costs of about 40 to 55 mills/kWh. 1 Current Programs The DOE program to improve pulverized coal-based power generation systems builds on several aspects of current pulverized coal power generation technology that are commercial or near-commercial, including: staged air and other combustion modification techniques for NOx control; selective noncatalytic NOx reduction using ammonia or amines; advanced (supercritical) steam conditions to 590 °C (1100 °F), 31 MPa (4,500 psia); combined power generation and space heating (hot water); combined power generation and process steam (cogeneration); coal-water slurry combustion with up to 70 percent coal by weight; and expansion turbine electricity generation using steam, hot combustion gases, or heated air. As shown in Table 7-1, there are three major components of the DOE RD&D (research, development, and demonstration) program on pulverized coal-based power generation systems: the APC (advanced pulverized coal) systems activity incorporating the LEBS (low-emission boiler system) program and the coal-fired cogeneration program; the IFC (indirectly fired cycle) system activity comprising the externally fired combined-cycle (EFCC) and HIPPS (high-performance power system) programs; and the direct coal-fired heat engines systems activity, incorporating two distinct but related power generation systems—direct coal-fired gas turbines and direct coal-fired diesels. The major technology goals for these programs are summarized in Table 7-1. The FY 1994 budgets for these activities were $9.1 million for advanced pulverized coal and $14.4 million for IFCs. Advanced Pulverized Coal The LEBS program is focused on improvement in currently available pulverized coal systems through integration with advanced combustion and emissions 1   Personal communication from C. McGowin, Electric Power Research Institute, to E.S. Rubin, Vice Chair, Committee on Strategic Assessment of DOE's Coal Program, May 1994.

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--> TABLE 7-1 DOE's Program Goals for Pulverized Coal Systems   Advanced Pulverized Coal Indirectly Fired Cycle: Externally Fired Combined-Cycle/ High-Performance Power System Direct Coal-Fired Heat Engines Technology Goals Low-Emission Boiler System Coal-Fired Cogeneration   Direct Coal-Fired Gas Turbines Direct Coal-Fired Diesels Net efficiency, percent 42 70 (total system) 50 40 45 Emissions, fraction of New Source SO2 1/3 Meet local regulations 1/10 Meet Meet Performance Standards NOx 1/3 Meet local regulations 1/10 Meet Meet (NSPS) Particulates 1/2 Meet 1/4 Not specified Not specified Air toxics emissions relative to 1990 Clean Air Act amendments Meet Meet Meet Meet Meet Solid wastes Salable Benign Benign/salable Not specified Not specified Capital cost, $/kW 1,400 NA 1,200 1,400 1,300 Electricity cost compared to current pulverized coal Lower NA 10 percent lower Lower Lower Commercial completion milestones Commercial demonstration by 2000 5 MW demonstration in 2001 Externally fired combined-cycle demonstration—1997; high-performance power system demonstration—2003 Proof of concept supporting projects complete in 1994 1.8-MW proof-of-concept demonstration in 1994 Development status Preliminary commercial design in 1994 System design completed in 1994 Development and testing of ceramic heat exchanger ongoing Complete in 1993 Complete in 1993 NA, not available Source: DOE (1993a).

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--> control technology and state-of-the-art supercritical steam generators. Three power system design teams are currently engaged in cost-shared systems analyses and preliminary design studies. Current designs include use of boiler combustion modification and advanced flue gas treatment systems (e.g., combined SO2/ NOx removal) to achieve cost-effective emissions control. Selection of final designs for further development is scheduled for early 1995, with engineering development and subsystem testing to be completed in 1996. Proof-of-concept facility construction and operation are scheduled to lead to commercial readiness during the year 2000 (Ruth, 1994). The related APC coal-fired cogeneration program is aimed at combined electricity and process steam generation in plants of 100 MW electric (MWe) or smaller (i.e., medium industrial and institutional markets). The program addresses constraints imposed on the use of coal in urban areas—including environmental constraints—and the market for process steam. Indirectly Fired Cycle IFC systems are advanced coal-based combined-cycle systems intended to compete with oil and gas-fired generation using conventional generation technology familiar to the utility industry. The EFCC variant necessitates the development of an advanced high-temperature ceramic heat exchanger to transfer the heat from coal combustion to an air stream that is the working fluid for a gas turbine. Thus, the turbine is not directly exposed to corrosive and abrasive coal combustion products. The ceramic heat exchanger tubes will allow clean filtered air from the gas turbine compressor to be heated to the turbine inlet temperature, eliminating the need for complex fuel preparation from pulverized coal (LaHaye and Bary, 1994). EFCC will demonstrate the combined-cycle including steam generation from the gas turbine and combustion exhaust gases, using current postcombustion emission controls (e.g., FGD plus fabric filter). Subsequent development of HIPPS will incorporate a new high-temperature advanced furnace—also requiring development-that integrates combustion, heat exchange, and emission controls. Although there is no consensus that DOE's goal for NOx emissions (Table 7-1) can be met by application of advanced state-of-the-art staged combustor technologies, some optimism has been expressed.2 A major incentive is to avoid the additional cost of flue gas treatment (e.g., selective catalytic reduction) to meet the emissions goal. Direct Coal-Fired Heat Engines DOE's direct coal-fired heat engines program is directed toward commercialization by the private sector of two types of coal-fired engines-a direct-fired 2   Personal communication from Janos M. Beer, Massachusetts Institute of Technology, to John P. Longwell, Chair, Committee on the Strategic Assessment of the DOE's Coal Program, July 25, 1994.

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--> gas turbine and a direct-fired diesel engine. The program is aimed at burning coal-water slurry fuels in a combustion turbine by using a sufficiently clean fuel or modifying the turbine. The program is intended to develop modified diesel engines to burn coal-water slurry fuels. Both programs were completed in 1993 and are not part of ongoing DOE activities. Technical Issues, Risks, and Opportunities Central station power generation technology using pulverized coal is commercially mature and widely implemented in industrialized countries around the world. The large base of existing capacity and expertise provides a strong incentive to seek environmental, efficiency, and cost improvements by enhancing pulverized coal technology. DOE's program goals for the LEBS system offer thermal and environmental performance goals comparable to the capabilities of state-of-the-art pulverized coal technology today (see Chapter 3), while EFCC and HIPPS offer a potential for significantly higher efficiencies. However, numerous technical challenges must be overcome if the program's environmental and efficiency goals for EFCC and HIPPS are to be met simultaneously with the cost goals, especially for the higher-efficiency systems. Some of the major technical challenges, well recognized by DOE, include development of key system components, notably a specialized ceramic heat exchanger for EFCC, a high-temperature advanced furnace for HIPPS, and reliable low-emission slagging combustor technology. An example of the technical challenges facing DOE is illustrated by the heat exchanger requirements for the EFCC system. Experimental studies in the 1940s on open-cycle, indirectly fired gas turbines using metallic heat exchangers did not allow sufficiently high turbine inlet temperatures for economic power production (Orozco, 1993). The use of ceramic materials may permit higher operating temperatures and resulting system efficiencies, but significant materials technology development is still required to achieve the performance targets projected in Table 7-1. The exit air temperature from current ceramic heat exchangers is limited by materials constraints (see Chapter 9) to approximately 1100 °C (2000 °F), significantly below the inlet temperatures of 1290 °C (2350 °F) for state-of-the-art turbines, or 1370 °C to 1425 °C (2500 °F to 2600 °F) for advanced turbines. If development of a high-temperature, high-pressure ceramic heat exchanger proves not to be feasible either technically or economically, a compromise solution may be considered where natural gas is used to reach a high turbine inlet temperature. In one scoping design study (Bannister et al., 1993) the heat supplied from natural gas was on the order of 30 to 40 percent of the heat supplied by coal for a ceramic heat exchanger limited to an operating temperature of 1100 °C (2000 °F) or less. In addition to these specific technical challenges, the DOE program emphasizes a ''unified approach," "synergies," and integration of components and sub-

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--> systems to achieve target efficiencies and reduce the cost of the commercialized technology (DOE, 1993a). To achieve these opportunities, substantial development and demonstration of integrated systems still remains. Findings Pulverized coal combustion systems are an established and mature technology for power generation, with comparatively limited opportunity for further performance enhancements based on a simple Rankine steam cycle relative to advanced combined-cycle systems. Thus, the market niche for the LEBS system is not clear. Environmental performance is comparable to state-of-the-art commercial systems available today, and the efficiency of the LEBS system is comparable to today's supercritical steam units. Potentially lower costs through system integration, however, could be of interest for near-term power generation markets. The indirectly fired combined-cycle systems have the potential for significantly higher efficiency. However, this higher efficiency depends on providing gas heated to 1260 °C to 1425 °C (2300 °F to 2600 °F), while heat exchanger materials are currently limited to 1100 °C (2000 °F). Increasing this temperature is a major materials challenge. The fallback strategy of depending on natural gas for increasing the gas temperature could provide an interim system. FLUIDIZED-BED COMBUSTION Background Fluidized-bed combustion (FBC) technology consists of forming a bed of finely sized ash, limestone (for sulfur removal), and coal particles in a furnace and forcing combustion air up through the mixture, causing it to become suspended or fluidized. The height of bed material suspended above the bottom of the furnace is a function of the velocity of the combustion air entering below the bed. Atmospheric "bubbling-bed" FBC technology has a fixed height of bed material and operates at or near atmospheric pressure in the furnace. In atmospheric circulating FBC technology, the combustion air enters below the bed at a velocity high enough to carry the bed material out of the top of the furnace, where it is caught in a high-temperature cyclone and recycled back into the furnace. This recycling activity improves combustion and reagent utilization. In all AFBC (atmospheric fluidized-bed combustion) designs, coal and limestone are continually fed into the furnace and spent bed material, consisting of ash, calcium sulfate, and unreacted or calcined limestone, is withdrawn at the rate required to maintain the proper amount of bed material for fluidization. The amount of coal fed into the bed is approximately 2 to 3 percent of the total weight of the bed material. The fluidization of the bed and the relatively

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--> small amount of coal present in the bed at any one time cause good heat transfer throughout the bed material, and the resulting bed temperature is relatively low, about 800 °C to 900 °C (1470 °F to 1650 °F). The fluidization and relatively low bed temperature enhance the capture of SO2 emitted during combustion and retard the formation of NOx. The features of in-bed capture of SO2 and relatively low NOX emissions, plus the fluid bed's capacity to combust a range of different fuels, are the main attractions of FBC as a power generation technology. Under some operating conditions, AFBC units also may produce higher levels of organic compounds, some of which may be potential air toxics. Current studies also indicate that AFBC units emit higher levels of N2O—a greenhouse gas—than other combustion systems (Takeshita, 1994). AFBC technology has been in commercial use worldwide for well over 50 years, primarily in the petrochemical industry and in small industrial steam generators that are a tenth to a hundredth the size of commercial power plant generators. In the United States, development of AFBC technology began in 1965, when DOE contracted for development of a low-cost, industrial-sized AFBC unit. AFBC development in the U.S. power generation sector began in the early 1980s, with support from the private sector, including EPRI (Electric Power Research Institute), and DOE. A 20-MW bubbling bed AFBC unit was constructed and operated by the Tennessee Valley Authority and EPRI beginning in 1980 and concluded in 1987. During this same period, four AFBC demonstration projects ranging in size from 80 to 160 MW were implemented as either retrofits or repowering of an existing unit. As a result of these demonstrations and similar installations abroad, AFBC technology became commercial by the end of the 1980s for industrial steam generation, cogeneration, and utility-scale applications. The next generation of FBC technology operates at pressures typically 10 to 15 times higher than atmospheric pressure. Operation in this manner allows the pressurized gas stream from a pressurized fluidized-bed combustion (PFBC) unit to be cleaned and fed to a gas turbine. The exhaust gas from the turbine is then passed through a heat recovery boiler to produce steam. The steam from the PFBC unit and that from the heat recovery boiler are then fed to a steam turbine. This combined-cycle mode of operation significantly increases PFBC system efficiency over the AFBC systems. If the PFBC unit exhaust gas can be cleaned sufficiently without reducing its temperature (i.e., by using hot gas cleanup systems), additional cycle efficiency can be achieved. Development of PFBC has been under way since 1969, when the British Coal Utilization Research Association began operating a PFBC test unit at Leatherhead, England. A significant portion of the test work conducted there over the next 15 years was supported by EPA, DOE, and the U.S. private sector. In the early 1980s a number of other PFBC test and pilot facilities were constructed in the United States and Europe. The United States, the United Kingdom, and the Federal Republic of Germany under the auspices of the International Energy

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--> Agency constructed an 85-MW thermal (MWt) PFBC unit that was placed in service in 1980. Early cooperation between the American Electric Power Service Company and ASEA STAL (now ASEA Brown Boveri, with its subsidiary ABB Carbon) led, in 1982, to the construction of a 15-MWt PFBC component test facility now located in Finspong, Sweden (Miller et al., 1982). State of the Art AFBC technology has achieved commercial acceptance, while PFBC technology is currently undergoing commercial demonstration. As of mid-1993, 293 bubbling bed and 276 circulating bed units were operating worldwide, with an average steam capacity of 235,000 lb/hr. About 43 percent of the steam capacity and 35 percent of the total number of units were sold in North America, mainly in the United States. EPRI has estimated that 75 percent of the U.S. capacity is circulating FBC technology. Independent power producers, rather than investor-owned utilities, have pushed the development of AFBC in the United States. The present generation of AFBC technologies has no difficulty meeting the current NSPS for steam electric power plants or industrial sources. PFBC technology is in the early stages of commercialization. Four PFBC units of less than 80 MW, two in Sweden, one in Spain, and one in the United States, have been placed in operation in the past four years. A fifth 71-MW unit is in initial operation in Japan. The DOE CCT program is sponsoring an 80-MW circulating PFBC project expected to be in commercial operation in mid-1997 (DOE, 1994a). In addition, the CCT program has selected a 95-MW second-generation PFBC project for funding. This advanced PFBC system will involve partial gasification of the coal, with the resulting fuel gas going to a topping combustor along with cleaned gases from a circulating unit that will receive char from the gasifier. Electricity is generated from the topping combustor and from a steam cycle coupled to the PFBC unit. An advanced system for hot gas cleanup will also be used in the demonstration. A fully integrated second-generation PFBC system is also scheduled to be tested at the 8-MWe level at the Power Systems Development Facility under construction in Wilsonville, Alabama, sponsored by DOE, Southern Company Services, and EPRI. This PFBC testing will evaluate the integration of all of the components in the PFBC system, with emphasis on the integration of hot gas cleanup ceramic filters and gas turbines (DOE, 1993a). Current Programs DOE funding for AFBC technology development ended in FY 1992. The current PFBC program is aimed at developing second-generation systems for electric power generation with performance goals as summarized in Table 7-2. The FY 1994 Office of Fossil Energy budget for PFBC was $24.1 million.

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--> TABLE 7-2 DOE's Program Goals for Pressurized Fluidized-Bed Combustion Systems   Pressurized Fluidized-Bed Combustion Technology Goals First-Generation Second-Generation Improved Second-Generation Net efficiency, percent 40 45 ≥50 Emissions, SO2 1/4 1/5 1/10 fraction of NOx 1/3 1/5 1/10 NSPS Particulates Not specified Not specified Not specified Air toxics emissions relative to 1990 Clean Air Act amendments Meet Meet Meet Solid wastes Not specified Not specified Not specified Capital cost, $/kW 1,300 1,100 1,000 Electricity cost compared to current pulverized coal 10 Percent lower 20 Percent lower 25 Percent lower Commercial completion milestones Commercial-scale demonstration—mid-1990s Commercial scale demonstrations—2000 Commercial-scale demonstration—2007 Development status 70- to 80-MW demonstration projects ongoing Systems development, integration, and testing ongoing Development initiated   Source: DOE (1993a). Technical Issues, Risks, and Opportunities AFBC systems, either in the bubbling bed or circulating bed configuration, constitute a commercially mature technology, and DOE has contributed in a major way to its success. To further enhance its commercial application, manufacturers need to refine the technology to achieve lower capital costs compared with modern pulverized coal (PC) plants, improved environmental performance, and improved operating efficiency. However, the time period for competitive application of this technology in the U.S. electric power production sector is now and in the immediate future. The availability and cost of natural gas, along with competition from modern PC plants, will dictate whether AFBC continues to be a technology of choice for environmental compliance and new capacity additions by independent power producers. Because most new coal plants currently are being constructed outside the United States, the greatest opportunity for this technology is in developing countries. PFBC technology is just beginning to be commercially demonstrated and

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--> offers significant design, performance, environmental compliance, and cost advantages over AFBC technologies. As noted earlier, a second-generation of PFBC technology offering additional performance (efficiency) benefits is entering the pilot and demonstration phase. These systems employ a coal pyrolyzer to produce a fuel gas that is burned in the turbine topping cycle. Since only a portion of the coal is gasified, this design has the potential for higher efficiencies than IGCC systems, where all of the coal is gasified. Maude (1993) estimates that the efficiency advantage may be approximately four percentage points. Because PFBC operates at a higher pressure and increased efficiency compared with AFBC, the same power output can be achieved with a unit that requires less land area (i.e., smaller "footprint" of equipment). The steam flows for PFBC units also are compatible with steam turbines at existing power plants. Thus, the technology is especially attractive for repowering existing units at existing power plant sites, avoiding the need and difficulty of developing new sites. The higher cost of equipment operating at higher pressures and temperatures is partially offset by the reduced equipment size and higher efficiency. Efficiencies on the order of 39 to 42 percent can be achieved with newer PFBC designs, compared with 34 percent efficiency for AFBC. EPRI estimates the capital cost of a 340-MW bubbling bed supercritical PFBC boiler (42 percent efficiency) at $1,318/kW (in 1992 dollars), with a total levelized cost of 37 mills/kWh (80 percent capacity factor, eastern bituminous coal) (EPRI, 1993a). Substantially higher efficiencies (45 to greater than 48 percent) are expected from second-generation PFBC systems. It is questionable whether the advanced PFBC systems can achieve DOE's goal of 20 to 25 percent reduction in electricity cost as well as capital cost reductions relative to current PC plants. In general, the higher degree of complexity of advanced systems makes it likely that capital costs will tend to increase rather than decrease, although the resultant efficiency gains will have a positive effect in lowering the cost of electricity. At present, however, there remains considerable uncertainty as to the future costs of advanced power systems. One of the key performance and cost uncertainties for advanced PFBC systems is the development of hot gas cleanup technology. Reliable hot gas particulate cleanup plus advanced (1370 °C [2500 °F] or higher) turbine systems will be required for PFBC technology to achieve DOE's projected performance potential of more than 50 percent efficiency while meeting environmental compliance requirements. At the present time these technologies are under development. The status of hot gas cleanup technology and advanced turbine systems (ATS) is discussed later in this chapter. Related issues concern the development of adequate SO2 and NOx controls and their associated costs. Current DOE flowsheets for advanced PFBC systems are beginning to incorporate the possible need for selective or nonselective catalytic reduction systems for NOx control in addition to the combustion controls inherent in FBC systems. Added NOX controls would increase the base cost of the

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--> used technology in conventional pulverized coal combustion systems. The particle-laden flue gas passes through an ionizing field, which imparts an electric charge to the particles, allowing them to be collected on an oppositely charged surface. Alternately, a fabric filtration system may be employed to collect particles by passing the flue gas through a fabric filter (baghouse) collector, which operates much like a high-efficiency vacuum cleaner. Current IGCC systems remove particulates by condensing or quenching the raw fuel gas with water (wet scrubbing). First-generation PFBC designs often employ cyclone (inertial) separators in conjunction with an ESP or fabric filter. Advanced IGCC and PFBC systems employ solid (typically ceramic) barrier filters that operate at high-temperature and pressure, in contrast to conventional low-temperature devices at atmospheric pressure. Sulfur dioxide is a component of flue gas resulting from the oxidation of sulfur in the coal during combustion. Sulfur dioxide can be controlled by reducing the sulfur content of coal prior to combustion, by reacting the SO2 with a reagent (typically calcium-based) either during or after combustion, or by a combination of both approaches. Postcombustion removal of SO2 using wet or dry FGD (flue gas desulfurization) systems is the most common technology for conventional power plants. For PFBC systems, the SO2 reacts with a sorbent injected directly into the fluid bed. This approach is also being examined as an option for IGCC systems employing fluidized-bed gasifiers. Gasification-based power systems convert sulfur to hydrogen sulfide (H2S) rather than SO2. Current IGCC systems employ cold gas cleanup to remove H2S via commercial low-temperature absorption systems. Advanced IGCC systems are being designed to remove H2S using an absorption-regeneration system at high temperatures to improve system efficiency. Any H2S remaining in the gas stream is oxidized to produce SO2 emissions when the fuel gas is burned to generate electricity. Nitrogen oxide emissions are formed from high-temperature reactions involving the oxygen and nitrogen present in coal and combustion air. Formation of NOx can be reduced by various measures that control the temperature-time profile of combustion reactions. Postcombustion control of NOx is typically accomplished by the injection of ammonia-based substances, with or without catalysts, that reduce NOx to nitrogen gas. In gasification-based systems, nitrogen in the fuel gas stream typically occurs as ammonia, which is converted to NOx upon combustion in the gas turbine. Cold gas cleanup systems remove most of the ammonia prior to combustion, thus lowering potential NOx emissions, while current hot gas systems do not. In the latter case, postcombustion controls could be required to meet applicable emissions standards. Most current methods of air pollution control generate some type of solid waste that must be disposed of or reused. At a minimum, the wastes include the mineral matter (ash) originally found in the coal. Other wastes arise from technologies to control SO2 emissions. Technologies and processes do exist to replace or eliminate many of these wastes through reuse or by-product production,

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--> but most of these options are not economical in the United States at the present time. Hence, their use is not widespread. In the future, however, waste minimization is expected to become increasingly important in response to new economic and environmental pressures. State of the Art Recent trends in particulate, SO2, and NOx emission reductions achievable with current technology for pulverized coal-fired power plants were addressed in Chapter 3 (see Figure 3-2). Particulate control technologies were the first to be developed, and their evolution has been undertaken primarily by the private sector with limited government support. Current ESPs and fabric filters achieve emission levels of one-third to one-sixth NSPS levels at costs of about $50 to $75/kW and about 2 to 4 mills/kWh in total electricity cost (Sloat et al., 1993). FGD technologies came into use in the United States in the 1970s and were developed throughout the 1980s with limited research and pilot plant efforts by EPA and DOE. Wet limestone systems, the most prevalent now in use, are being designed today for up to 95 percent annual average SO2 removal, with about 97 to 98 percent removal using organic acid additives, in contrast to 90 percent removal a decade ago. Wet scrubbers using magnesium-enhanced lime systems are the most efficient FGD units now deployed, achieving over 98 percent SO2 removal (Makansi, 1993a). For the typical plant shown earlier in Figure 3-2a, this corresponds to an emission rate of 0.1 lb SO 2/million Btu, or one-sixth the NSPS level. On low-sulfur coals, lime spray dryer systems, originally deployed as a 70 percent removal technology, today are designed for over 90 percent SO2 removal in the United States and over 95 percent in Europe. The cost of FGD systems also has decreased significantly as a result of process improvements and design simplifications over the past decade. Typical capital costs for application with a new power plant now range from about $100 to $200/kW, with total levelized costs of about 5 to 10 mills/kWh (Keeth et al., 1991). Capital costs for retrofit systems are typically higher than those cited above. For example, the capital cost of most FGD systems announced for Phase I compliance with the 1990 CAAAs (Clean Air Act amendments) range from $220 to $260/kW (Colley et al., 1993). For NOx control, advanced low-NOx burner designs and other combustion modifications now available or nearing commercialization are able to achieve emission reductions of 30 percent or more below the NSPS level for new PC-fired power plants (Kokkinis et al., 1992). Costs are relatively low, at roughly $7 to $15/kW (EPRI, 1993b). Retrofit situations pose greater difficulties for coal plants due to the wide variety of boiler types and plant vintage. To date, NOx reductions from existing coal-fired units have not yet been widely undertaken or required to meet the ambient NO2 standard. Postcombustion NOx removal systems employing selective catalytic reduc-

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--> tion (SCR) technology are now in widespread use on coal plants in Japan and Germany, with about 30 GW of installed capacity (Scharer and Haug, 1993). Current SCR technology achieves up to 90 percent NOx removal in low- and medium-sulfur coal applications overseas (Makansi, 1993b). Such systems have not yet been deployed in the United States, although demonstration of SCR with U.S. coals currently is in progress as part of DOE's CCT program. A commercial order also has been placed for SCR on a 285-MW coal-fired plant operated by an independent power producer (Makansi, 1993b). The cost of SCR remains high relative to combustion controls, although a decade of experience and the emergence of industry competition have lowered the cost significantly. Capital costs today are roughly $50 to $80/kW, with total levelized costs of about 2 to 6 mills per kilowatt-hour for hot-side systems on new coal-fired plants (EPRI, 1991c). SCR costs are dominated by the cost of the catalyst and frequency of catalyst replacement. Substantial cost reductions have been achieved in both areas in recent years. Retrofit costs for SCR can be significantly higher depending on the level of difficulty, the size and age of the plant, and other factors. For gas turbine systems, SCR already is required on some U.S. plants to meet local air quality standards. NOx emission levels of 9 ppm or less are being achieved (Makansi, 1993b). Gas turbine designers also are employing a variety of combustion-based control measures in efforts to avoid the need for tail-end SCR. The DOE CCT program has resulted in significant joint federal and private sector funding for the further development and demonstration of advanced emission control technologies. As elaborated in Chapter 8, this program includes the commercial demonstration of 19 emission control systems, with five completed, 11 in operation, and three in design and construction. Table 7-8 shows the control levels projected to be achieved by the emission control systems in the CCT program and indicates whether the technologies can be utilized for new facilities or as retrofits on an existing facility. In addition to the emission control systems above, advanced systems employing hot gas cleanup and in-bed desulfurization are being developed. For PFBC systems, the current state of the art for sulfur removal employs a circulating PFBC designed to achieve SO2 removal efficiencies of 95 percent or more (DOE, 1994a). Scale-up and demonstration of this capability are planned under Round V of the CCT program. The goal is to achieve SO2 reductions comparable to modern FGD systems at reagent stoichiometries low enough to permit economical operation with minimum solid waste. At the present time, relatively high reagent use often is required to achieve high SO2 removal efficiencies. The spent and unreacted sorbent roughly doubles the total solid waste for coal-fired plants. Hot gas desulfurization systems that achieve over 99 percent sulfur removal from gasifier fuel gas streams also are scheduled for demonstrations in conjunction with several IGCC CCT projects. To date, hot gas (480 °C to 700 °C [900 °F to 1300 °F]) desulfurization systems employing regenerable metal oxides such as

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--> TABLE 7-8 Combustion-Related Emission Control Systems in the Clean Coal Technology Program Project Removal Efficiency (percent) Applicability   SO2 NOx New Retrofit Sulfur Dioxide Removal Gas suspension absorption 90+   X X Confined zone dispersion 50     X Furnace sorbent injection with humidification (LIFAC) 85   X   Advanced flue gas desulfurization 95+   X X CT-121 flue gas desulfurization system 98+   X X NOx Removal Cyclone fired coal reburn   55   X Low-NOx cell burner   50+   X Low-NOx burner-gas reburn   70 X X Advanced combustion-wall fired   50 X X Advanced combustion-tangentially fired   48 X X Selective catalytic reduction   80 X X Micronized coal reburn   60 X X Combined SO2/NOx SNOX catalytic advanced flue gas cleanup 96 94 X X Limestone injection multistage burner 70 50   X SNRB combined SOx and NOx control 85 90 X X Low-NOx burners and gas reburn 50 70   X NOxSO dry regenerable flue gas cleanup 97 70 X X S-H-Ua wet FGD 95 30 X X Dry NOx/SO2 70+ 80+ X X a Saarberg Holter Umwelt. Source: DOE (1994a). zinc ferrite and zinc titanate have not achieved the durability required for a cost-effective process. Continued work on improved sorbents and reactor designs is in progress (DOE, 1994b). System studies for IGCC systems using advanced fluidized-bed gasifiers also suggest that the optimal SO2 removal system may be a combination of hot gas desulfurization and in-bed desulfurization in the gasifier using limestone. Hot gas particulate removal from PFBC and IGCC gas systems also is under development. These devices can be viewed as an integral component of the power generation system rather than as an environmental control technology, since they serve the critical function of removing particles and alkaline materials from the fuel gas to protect the gas turbine from erosion and corrosion. For current and advanced turbine designs, the cleanup requirements needed to protect

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--> the turbine from particle-induced damage exceed the current requirements for environmental protection. The most promising systems to date have employed barrier filters designed to achieve emissions of less than 2 ppm by weight of particles greater than 5 microns in diameter. The major problem, however, has been longevity. Current candle filter designs have operated no more than several hundred hours at the required temperatures (760 °C to 870 °C [1400 °F to 1600 °F]) before breaking, whereas lifetimes on the order of 16,000 hours are needed for economical PFBC systems (DOE, 1994c). Improved designs, as well as testing in the reducing gas environment of IGCC systems, are planned as part of the CCT demonstration projects. With respect to solid waste emissions, many state-of-the-art air pollution control systems offer improved prospects for waste reduction through the production of salable by-products, especially with regard to sulfur emissions control. Modern FGD systems produce gypsum, which can be upgraded to commercial quality and sold (which is common practice in Europe and Japan). Several advanced flue gas cleanup systems being demonstrated in the CCT program produce by-product sulfur or sulfuric acid, as do the hot and cold gas cleanup systems employed with coal gasifiers. Only advanced PFBC systems increase rather than decrease the total solid wastes generated from coal use. In all cases the economic viability of by-product recovery systems depends on site-specific factors and markets. In the United States today, waste disposal in landfills is still more attractive for many electric utilities. Technical Issues, Risks, and Opportunities Existing control technologies for the criteria air pollutants (SO2 , NOx, and particulates) associated with PC-fired power plants are capable of meeting current or anticipated emission reduction requirements in the near-term (i.e., prior to 2005). The same is true of cold gas cleanup control technologies for gasification-based systems. Cost reduction and minimization of solid waste remain important goals to improve the viability of these coal-based systems. For the medium term (post-2005), additional performance improvements also may be required, especially for NOx controls. Control technologies applicable to advanced combustion and gasification technologies need further development. In particular, hot gas cleanup systems for SO2 and particulate removal, which are critical to several of the advanced high-efficiency technologies-especially PFBC-have yet to achieve the performance, reliability, or durability needed for commercial applications. In IGCC systems, hot gas cleanup does not presently control nitrogen emissions (in the form of gaseous ammonia), which increases downstream costs and complexity for NOx controls in the gas turbine/heat recovery system. Research to address these issues is in progress. With respect to solid waste minimization, one of the key needs is to improve

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--> the sorbent utilization for sulfur removal in advanced fluidized-bed combustors and gasifiers. Current PFBC systems produce the largest volume of solid waste per unit of sulfur removed. The presence of unreacted lime (as well as sulfides in the case of gasifiers) adds to the difficulty and cost of waste disposal. Pilot plant data for circulating PFBC designs show improved sorbent utilization relative to bubbling bed designs, but more work is needed to achieve commercially acceptable systems. More intensive research on reuse of spent sorbent also is needed if DOE's goal for solid waste reduction is to be achieved. Control technologies for noncriteria pollutants also need to be addressed. To deal with the emerging issue of air toxics (see Chapter 3), trace substance emissions and fate must be characterized for current and advanced technologies. It is anticipated that existing high-efficiency particulate control technologies will be adequate to deal with most heavy metal emissions from coal combustion, but specific regulations have yet to be established. Similarly, the extent to which vapor-phase emissions such as mercury, chlorides, and selenium will have to be controlled is not yet clear; technologies to control these emissions may well be needed in the near future. Should that be the case, an additional risk of hot gas cleanup systems is their uncertain capability to control emissions of air toxics, since they presently do not remove vapor-phase species. Additional controls for air toxics may impose additional economic costs. The ability of control technology to reduce or eliminate emissions of potential air toxics is currently under study by DOE, EPRI, and others. The most prevalent data are for conventional cold-side ESPs, which show high removal efficiencies for most heavy metals but much lower removal rates for volatile species such as mercury (Rubin et al., 1993). Wet FGD systems in conjunction with an upstream particulate collector appear to offer the greatest removal rates of volatile species and other potential air toxics such as chlorides. However, there is large uncertainty in the data, with relatively little information currently available for wet scrubbers operating in the United States. Experiments with carbon-based additives show an enhanced ability to remove mercury in some cases, particularly with high chloride coals. Research on novel control methods for air toxics is being pursued by EPRI, DOE, and others. As noted in Chapter 3, a major concern for all coal-based technologies is the potential requirement to control carbon dioxide (CO2) emissions. The most economical means is to improve the efficiency of energy conversion and utilization so that less CO2 is emitted per unit of useful energy delivered. For coal-fired power plants, average U.S. energy losses are about 2 percent in coal preparation, 67 percent in power generation, and 8 percent in transmission and distribution (EIA, 1993), yielding an overall efficiency of about 30 percent for fuel to delivered electricity. Within the limits of thermodynamic cycles, the greatest opportunity for energy efficiency improvements thus lies in the power generation process. As noted previously, the most efficient PC-fired plants commercially available today have efficiencies in the range of 38 to 42 percent. Thus, advanced

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--> technologies achieving 50 to 60 percent efficiency offer the potential to reduce CO2 emissions up to a third relative to current new plants. The potential for CO2 capture and disposal also has received preliminary study (Ormerod et al., 1993; MIT, 1993; EPRI, 1991a). The consensus is that the technological means of scrubbing CO2 from flue gases already exists today but that the feasibility of CO2 disposal in deep wells, oceans, or other final storage sites remains a critical issue to be resolved. From a cost viewpoint, CO2 removal today is very expensive. Estimates for a 90 percent CO2 reduction suggest roughly a doubling of electricity generation costs and about a 35 percent energy penalty for removing and transporting CO2 to a hypothetical disposal site (NRC, 1992). Somewhat lower energy penalties are estimated for advanced combustion and gasification cycles. The development of viable CO2 removal and disposal processes remains a long-term challenge to control technology development. Current DOE Programs The Control Technology program in the Office of Fossil Energy is divided into four program components: Flue Gas Cleanup, Gas Stream Cleanup, Waste Management, and Advanced Research. As noted in Chapter 2, DOE has established incremental emission control goals for its Advanced Power Systems program (Table 2-3) that must be supported by the Control Technology program. The FY 1994 authorized budget for this activity was $13.25 million for flue gas cleanup, $19.29 million for gas stream cleanup, $2.41 million for waste management, and $1.16 million for advanced research. As noted previously, commercial technology developed by the private sector with DOE participation already can achieve the DOE emission goals for 2000 and 2005 for conventional coal combustion systems. With the anticipated increase in demand for baseload generating capacity beyond 2005 and the expected tightening of future emission control requirements, the DOE program emphasis on developing improved control technologies for highly efficient, "superclean" power systems appears to be well placed. The Flue Gas Cleanup program has a goal of reducing SO2, NOx, and particulate emissions to one-tenth current NSPS levels without high-volume waste generation (DOE, 1993a). Further goals are to control air toxics and CO2 emissions and to develop salable by-products from the control systems. Development of advanced FGD systems and combined SO2/NOx removal systems is also part of this program area. The other major component is the Gas Stream Cleanup program. It has a similar focus of removing contaminants from gasifier or combustor streams prior to their entry into advanced power systems such as the PFBC, IGCC, and IGFC systems. Activities focus on the development of high-temperature, pressurized contaminant control systems. DOE also has a Waste Management program focused on waste products formed by advanced power generation technologies. The goal of that program is

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--> to ensure that solid waste from advanced fossil energy technologies is not a roadblock to commercialization of those technologies. More specifically, the objectives are to achieve a 50 percent utilization of solid waste from advanced fossil energy technologies and commercial markets by 2010, to establish use for mine remediation of alkaline by-products such as are produced by fluidized-bed combustors and gasifiers with limestone added for sulfur removal, and to provide commercial acceptance of products manufactured from advanced pulverized coal by-products (DOE, 1993a). Many examples of successful waste product recycling, such as the use of flyash, exist. The best uses for the future are generally considered to be in construction, agriculture, mine reclamation, and soil stabilization. The present cost of these options and the enormous quantities of waste relative to by-product demand are the principal roadblocks to increased commercialization. The final component of the Control Technologies Program is Advanced Research. The emphasis in this part of the program is on fundamental hot gas cleanup methods such as ceramic filter and membrane research. Findings Current commercial technologies for SO2, NOx, and particulate control for pulverized coal plants have improved substantially over the past decade and now can meet or exceed DOE's air pollutant emission targets for 2000 and 2005. Cost reduction is the primary need and the main potential benefit of current CCT demonstration projects. The most difficult near-term R&D challenges are in development of the hot gas particulate and sulfur cleanup systems to be employed with advanced power generation systems (IGCC, PFBC, IGFC). In particular, the technical problems of achieving reliable and sustained operation have yet to be overcome. Solutions to these problems are central to the achievement of cost-effective, high-efficiency power generation systems. Especially critical is the need for a high-temperature, high-pressure particulate removal system for advanced PFBC. Other DOE programs are beginning or continuing to address the emerging issues of hazardous air pollutants (air toxics), greenhouse gas emissions (especially CO2), and solid waste minimization. All of these are important issues that will require increased R&D attention in the future. REFERENCES Angrist, S.W. 1976. Direct Energy Conversion, 3rd Ed. Reading, Massachusetts: Addison-Wesley. Bannister, R.L., F.P. Bevc, W.F. Domeracki, and T.E. Lippert. 1993. Advanced coal-fired combined-cycle power plant technology alternatives. Presented before the Coal-Fired Power Plant Upgrade Conference, Warsaw, Poland, June 15-17. Orlando, Florida: Westinghouse Electric Corporation, Power Generation Business Unit.

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--> Colley, J.D., J.T. Waddell, and G.A. Hollinden. 1993. Development and Status of Flue Gas Desulfurization Technology Worldwide. Paper presented at the Eleventh International Conference on Power Stations, Association des Ingenieurs de l'Institut Montefiore, Sept., Liege, Belgium. DOE. 1993a. Clean Coal Technologies: Research, Development, and Demonstration Program Plan. U.S. Department of Energy, DOE/FE-0284. Washington, D.C.: DOE. DOE. 1993b. FY 1994 Congressional Budget Request. U.S. Department of Energy, DOE/CR-0012, Vol. 4. Washington, D.C.: DOE. DOE. 1994a. Clean Coal Technology Demonstration Program: Program Update 1993. U.S. Department of Energy, DOE/FE-0299P. Washington, D.C.: DOE. DOE. 1994b. Summary of Hot Gas Desulfurization and Direct Sulfur Recovery Process Activities in the Fossil Energy Advanced Power Systems Program. U.S. Department of Energy, Office of Fossil Energy, Washington, D.C.: DOE. DOE. 1994c. State-of-the-Technology: Hot Gas Particulate Filtration. U.S. Department of Energy. Washington, D.C.: DOE. DOE. 1994d. FY 1995 Congressional Budget Request. U.S. Department of Energy, DOE/CR-0023, Vol. 4. Washington, D.C.: DOE. EIA. 1993. Annual Energy Review 1992. Energy Information Administration. U.S. Department of Energy, DOE/EIA-0384(92). Washington, D.C.: DOE. Electric Light and Power. 1993. Utilities advance power plant efficiency. Electric Light and Power 71(10): 9. EPRI. 1983. Site Specific Assessment of a 150 MW Coal Gasification Fuel Cell Plant. Prepared by KTI Corporation for the Electric Power Research Institute, EM-3152. Palo Alto, California: EPRI. EPRI. 1991a. Engineering and Economic Evaluation of CO2 Removal from Fossil Fuel-Fired Power Plants. Prepared by Fluor Daniel, Inc., for the Electric Power Research Institute, IE-7365, Vol. 1 and 2. Palo Alto, California: EPRI. EPRI. 1991 b. A Comparison of Humid Air Turbine (HAT) Cycle and combined-cycle Power Plants. Prepared by Fluor Daniel, Inc. for the Electric Power Research Institute, IE-7300. Palo Alto, California: EPRI. EPRI. 1991c. Technical Feasibility and Cost of Selective Catalytic Reduction NOx Control. Electric Power Research Institute, GS-7266, authored by C. Robie and P. Ireland. Palo Alto, California: EPRI. EPRI. 1992a. Evaluation of Westinghouse Solid Oxide Fuel Cell Technology for Electric Utility Applications in Japan. Prepared by Westinghouse Electric Corporation for the Electric Power Research Institute, TR-100713. Palo Alto, California: EPRI. EPRI. 1992b. Technical and Economic Assessment of Molten Carbonate Fuel Cell Manufacturing Costs. Prepared by Michael A. Cobb and Company for the Electric Power Research Institute, TR-101525. Palo Alto, California: EPRI. EPRI. 1993a. TAGTM Technical Assessment Guide. EPRI TR-102275-VIR7. Vol. 1, Rev. 7, p. 876. Palo Alto, California: EPRI. EPRI. 1993b. Applications of Carbonate Fuel Cells to Electric Power Systems. Prepared by Fluor Daniel, Inc., for the Electric Power Research Institute, TR- 102931. Palo Alto, California: EPRI. EPRI. 1993c. A Feasibility and Assessment Study for FT-4000 Humid Air Turbine. Prepared by Fluor Daniel, Inc. for the Electric Power Research Institute, TR-102156. Palo Alto, California: EPRI. EPRI. 1993d. Engineering and Economic Evaluation of Integrated Gasification Compressed Air Storage with Humidification. Prepared by Bechtel Group, Inc., for the Electric Power Research Institute, TR-103347. Palo Alto, California: EPRI. Gilbert/Commonwealth, Inc. 1992. Ultra Supercritical Power Plants. Group discussion during meeting with ELSAMPROJEKT, EPRI, Sargent & Lundy, and Gilbert/Commonwealth, Inc., at Gilbert/Commonwealth, Reading, Pennsylvania, October 13.

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--> Sloat, D.G., R.P. Gaikwad, and R.L. Chang. 1993. The potential of pulse-jet baghouses for utility boilers. Part 3: Comparative economics of pulse-jet baghouses, precipitators and reverse-gas baghouses. Journal of the Air and Waste Management Association 43(Jan.): 120-128. Takeshita, M. 1994. Fluidized-Bed Combustion for Coal-Fired Plants: Environmental Performance. London: IEA Coal Research. Wolk, R.H., and N.A. Holt. 1994. Overview of Global Utility Market for Advanced Coal-Fired Systems. Paper presented at the Coal-Fired Power Systems 94-Advances in IGCC and PFBC Review Meeting, U.S. Department of Energy, Morgantown Energy Technology Center, Morgantown, West Virginia, June 21-23.