National Academies Press: OpenBook

Coal: Energy for the Future (1995)

Chapter: 7 ELECTRIC POWER GENERATION

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Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

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

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

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

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

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.

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

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).

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

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.

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

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-

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

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

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

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

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

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.

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

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

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

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

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

plant. Also of concern is the reagent requirement for sulfur removal and the resulting solid waste generation. As elaborated later in this chapter (see "Emission Control Technologies"), increasingly stringent requirements for SO2 removal are becoming more difficult or more costly to achieve with fluidized-bed systems, which also generate larger quantities of solid waste than new PC plants with FGD. An increase in solid waste generation is inconsistent with DOE's goals for advanced power systems, which seek sizeable reductions in solid waste. Thus, there is a need to demonstrate efficient environmental designs and to address potential by-product markets for spent reagent in order to reduce solid waste impacts.

Findings

AFBC systems are a mature commercial technology, and, as such, DOE is no longer pursuing additional R&D on this technology. Significant performance improvements are expected for PFBC systems, which are now beginning to be commercialized. The DOE performance goals for the PFBC program appear to be reasonable for the first- and second-generation systems. The capital cost goals for all generations appear to be optimistic, especially as the number of components and complexity of the system are increased for the second-generation and improved second-generation systems. A major uncertainty still facing PFBC systems is the reliability and cost of hot gas particulate controls. Reduction of solid wastes, economical high SO2 removal efficiencies, and generation of supercritical steam in a fluidized-bed are other issues to be addressed.

INTEGRATED GASIFICATION COMBINED-CYCLE SYSTEMS

Background

Coal gasification is a method of producing a combustible gaseous fuel from almost any type of coal. The current status of gasification technology and opportunities for efficiency enhancement have been discussed in Chapter 6. Gasification is a key step for advanced conversion of coal to electricity using IGCC systems. An IGCC power plant is a gasification facility coupled to a gas-fired combined-cycle unit. Based on current environmental control capabilities, IGCC offers a coal-based power technology with low emissions, high thermal efficiency, and the potential for phased construction—that is, building simple-cycle natural-gas-fired combustion turbines first, then converting to combined-cycle, and finally adding coal gasification as gas prices increase or gas availability deteriorates. Future advances in gasification-based power production are linked to increases in gas turbine firing temperature, hot gas cleanup of the fuel gas, coproduction of both chemicals and electricity, improved gasifier designs, and integration of gasification with advanced cycles and fuel cells.

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×
State of the Art

Components of IGCC technology have been under development for some time, and several competing coal gasification processes now have successful commercial-scale operating records (see Chapter 6). These include the Texaco, Shell, and Destec (formerly Dow) entrained-flow processes and the Lurgi moving bed process. Other gasification processes have been successfully tested at pilot scale and are ready for scale-up to commercial size, including the Prenflo entrained-flow, the British Gas/Lurgi moving bed, and the KRW and the high-temperature Winkler fluidized-bed processes.

The IGCC concept was first successfully demonstrated at the 100-MW scale at Southern California Edison's Cool Water Station in Daggett from 1984 to 1989

TABLE 7-3 IGCC Power Plant Performance and Economics Based on Shell Gasification Technology and Eastern Bituminous Coal (all costs in constant 1992 dollars)

Plant Parameter

Value

Nominal size, MW

500

Thermal efficiency (HHV basis)

 

% Fuel to power

42

Net heat rate, Btu/kWh

8,900

Total capital cost, $/kW

1,613

Levelized cost of electricity,a mills/kWh

41

a Assuming a capacity factor of 80 percent and a levelized coal price of $1.30/106 Btu.

Source: EPRI (1993a).

using the Texaco entrained-flow coal gasification process. Destec is currently operating a 160-MW IGCC plant in Plaquemine, Louisiana, using a two-stage, entrained-flow coal gasification process. In the Netherlands, SEP (the joint authority for electricity production) has begun operation of a 250-MW IGCC plant based on the Shell entrained-flow coal gasification process. Each of these plants employs gas turbines with firing temperatures of about 1100 °C (2000 °F).

Table 7-3 summarizes the performance and economics for a hypothetical 500-MW first-generation IGCC plant employing a state-of-the-art, oxygen-blown, entrained-flow gasification process to provide fuel gas to advanced combustion turbines. The IGCC plant is fueled with an eastern bituminous coal, is highly integrated, and employs cold gas cleanup. The cost for current systems is significantly higher than the DOE goals for advanced systems shown later in Table 7-4.

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×
Technical Issues, Risks, and Opportunities

First-generation IGCC plants have already demonstrated outstanding operability and environmental performance at commercial scale. The key issue for these technologies is the impact of high capital cost on economic competitiveness. Chapter 6 discussed technical issues and opportunities related to coal gasifiers. Reductions in the capital costs of IGCC systems can be accomplished through simplification and optimization of the process, economies of scale, and/or through thermal efficiency gains. Future improvements to the economics of IGCC, therefore, are linked mainly to development of advanced gas turbines with firing temperatures over 1370 °C (2500 °F) and secondarily to development of reliable hot gas cleanup schemes. Both of these subjects are discussed later in this chapter. As noted in Chapter 6, energy losses in gasification and gas cleanup amount to about 15 to 20 percent of the total coal energy input, resulting in a loss of 5 to 10 percentage points in power generation efficiency. Thus, improved gasifier designs with lower energy losses also can contribute to overall efficiency improvements. Current systems studies suggest that the integration of gasification with advanced cycles, such as the humidified air turbine, and compressed air storage with humidification, also has the potential to reduce capital costs and provide competitive intermediate-load capacity (EPRI, 1991b, 1993c,d). The highest-efficiency system proposed by DOE and based on gasification is an integrated gasification advanced-cycle (IGAC) system based on a humidified gas turbine (DOE, 1993a).

Current Programs

DOE's program goals for IGCC systems are summarized in Table 7-4. The FY 1994 Fossil Energy coal program authorization for IGCC was $27.2 million. The DOE CCT program also includes several gasification-based power projects, which represent the state of the art and encompass both entrained-flow and fluidized-bed gasification systems. Table 6-3 summarized the status of these CCT projects. The completion of the CCT programs in about five or six years will provide the data and experience for subsequent commercial IGCC plants to be employed beyond the year 2000. Table 7-5 summarizes the major European IGCC projects in progress. Except for the Buggenum project (Table 7-5), all the combustion turbines are 1300 °C class (2350 °F). Other IGCC projects are also planned for Asia.

Findings

IGCC offers a coal-based power technology with low emissions, the potential for higher thermal efficiency, and the capability for phased construction.

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

TABLE 7-4 DOE's Program Goals for Integrated Gasification-Based Systems

Technology Goals

Second-Generation Integrated Gasification Combined-Cyclea

Integrated Gasification Advanced-Cycle

Integrated Gasification Fuel Cell

Net efficiency, percent

45 (by 2000)

≥50 (by 2010)

≥60 (by 2010)

Emissions,

SO2

1/10

1/10

1/10

fraction of

NOx

1/10

1/10

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

1,200

1,050

1,100

Electricity cost compared to current pulverized coal

20 Percent lower

25 Percent lower

20 Percent lower

Commercial completion milestones

Demonstration 2001

Demonstration 2004

Coal demonstration 2000

Development status

Under development

Development initiated

Current activities focusing on natural gas-fired systems

a First-generation integrated gasification combined-cycle power systems are presently at the commercialization stage and are being demonstrated with design improvements in the CCT program.

Source: DOE (1993a).

First-generation IGCC plants have already demonstrated outstanding operability and environmental performance at commercial scale. The key issue for these technologies is the high capital cost and its impact on economic competitiveness.

Gasification is an enabling technology that allows the use of very high-efficiency energy conversion devices—such as high-temperature gas turbines and fuel cells—for power production in combined-cycle systems. Reductions in capital costs can be accomplished through process simplifications, economies of scale, and thermal efficiency improvements. With completion of the DOE CCT programs and the major European demonstration projects in the next five to six years, areas for continued improvements to the gasification technologies and IGCC process can be identified to reduce the capital cost and enhance the economic competitiveness.

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

TABLE 7-5 Major European IGCC Projects in Progress

Project

Technology

Efficiency (percent)

MW (net)

Startup

SEP, Buggenum, Netherlands

Shell entrained Oxygen-blown Cold gas cleanup Siemens V94.2 gas turbine

41

253

January 1994

ELCOGAS, Puertollano, Spain

PRENFLO entrained Oxygen-blown Cold gas cleanup Siemens V94.3 gas turbine

43

300

Mid-1996

RWE, KoBra, Hurth, Germany

HT Winkler fluid bed Air-blown Cold gas cleanup Siemens V94.3 gas turbine

43

312

Post-2000

 

Source: Wolk and Holt (1994).

INTEGRATED GASIFICATION FUEL CELL SYSTEMS

Background

Fuel cells are electrochemical energy conversion devices that convert the chemical energy in a fuel and oxidant directly to electricity without direct combustion. They can be thought of as ''gas batteries" where the electrochemically active materials are gases that can be ducted to the electrodes from outside the battery case. The reaction products are also gases and can be removed similarly. A fuel cell can be "discharged" continuously to produce electricity so long as the reactants are supplied and the products removed.

The fuel cell has many of the same features as a battery. The power production takes place at a constant temperature; hence, it is not constrained to the theoretical upper limit for heat engines (known as the Carnot cycle efficiency). Thus, fuel cells potentially can be much more efficient than combustion-based systems. Environmentally, the electrochemical reactions do not involve direct combustion, so thermal NOx production is negligible. Reactants are consumed exactly in proportion to the electric energy output, so the efficiency remains high even when the level of power production is reduced.

In practice, fuel cell system efficiencies remain limited by energy losses and inefficiencies inherent in most engineered systems. Continued R&D is aimed at reducing these losses to improve overall efficiency. An attraction of fuel cell

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

systems is that natural gas or coal-derived fuel gas both make suitable fuels for running a fuel cell system. Interest in fuel cells as an energy conversion system stems primarily from the fact that they offer the highest efficiency and lowest emissions of any known fossil-fueled power generation technology.

State of the Art

Fuel cells first came to public attention in the 1960s because of their importance in the manned space program. Today, commercially available fuel cell systems are based on phosphoric acid fuel cell (PAFC) technology and are configured for small-scale commercial and residential cogeneration applications. These systems use natural gas or other light hydrocarbons as fuel. They typically yield 36 percent net electrical efficiency and over 70 percent total efficiency if all thermal energy is used (e.g., for space heating). This type of fuel cell operates at approximately 200 °C (400 °F), too low a temperature for the thermal energy to be efficiently converted to useful work in a bottoming cycle. ONSI Corporation has delivered nearly 60 of the 200-kW PAFC cogeneration systems. Plant reliability and availability based on experience to date have been outstanding.

Molten carbonate fuel cells (MCFC) using a molten alkali-metal carbonate electrolyte operate at approximately 650 °C (1200 °F), a temperature where rejected heat can be used efficiently in a bottoming cycle and where conventional materials still can be used for the balance of plant equipment. This type of fuel cell power plant is just entering the demonstration phase of development. Power plants from several U.S. and Japanese manufacturers ranging in size from 200 kW to 2 MW are planned to be in operation in 1995. These plants are expected to enter the utility market as 1- to 5-MW units, natural gas fueled, with electrical generation efficiency greater than 50 percent (without a bottoming cycle) by the year 2000. In larger sizes, with steam or gas bottoming cycles, efficiency will be 60 percent or higher when using natural gas fuel (EPRI, 1993b).

The solid oxide fuel cell (SOFC), of which the basic building block is an oxide-ion conducting ceramic electrolyte, operates at an even higher temperature (980 °C [1800 °F]). The potential for future cost reduction makes SOFCs attractive. The most successful system to date is the Westinghouse tubular design that has been operated in units of up to 20 kW for over 6,000 hours. The key fabrication issue is the use of chemical vapor deposition to fabricate these tubular components, which is expensive. A great deal of current research is focusing on simpler planar systems that show promise for less expensive fabrication techniques. The largest planar unit under test at this time is I kW. It is anticipated that the scale will be increased to 10 kW within one year.

Fuel cells integrate readily with coal gasifiers. Such IGFC systems are potentially the most efficient and least polluting method to generate electricity from coal. Characteristics of the three types of fuel cells integrated with coal gasifiers are given in Table 7-6. EPRI (1993b) estimates that integrated gasification mol-

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

TABLE 7-6 Integrated Gasification Fuel Cell System Characteristics

Parameter

Phosphoric Acid Fuel Cell

Molten Carbonate Fuel Cell

Solid Oxide Fuel Cell

Design plant size (MW)

150

440

300

System efficiency on coal (% HHV)

33.5

51.3

46.6

NOx, SOx, VOCsa total (lb/MWh)

<1

<1

<1

Total capital cost (1992 $/kW)

2,210

1,896

2,107

Year of commercial demonstration on natural gas

1993

1998

1998

a Volatile organic compounds.

Sources: EPRI (1983, 1992a, 1993b).

ten carbonate fuel cells based on current state-of-the-art entrained-flow gasification will have a full-load efficiency around 50 percent. Because of energy losses of about 15 to 20 percent inherent in gasification (see Chapter 6), major advances in gasification technology will be required to meet the DOE IGFC efficiency goal of 60 percent or greater. The total capital requirement is approximately $1,900/ kW, and the cost of electricity is not yet competitive with other gasification-based power systems. The capital cost must be reduced by approximately 20 percent to make the systems competitive. This is generally considered feasible, with technological advances already planned for the fuel cell and gas cleaning subsystems within the plant.

Technical Issues, Risks, and Opportunities

IGFC will not materialize for utility-scale electricity generation until the fuel cells are first used commercially as small-scale distributed generators on natural gas. This in turn requires demonstration that engineering development issues are resolved and that the fuel cells themselves have the reliability and durability necessary for utility service. Since demonstration projects are costly, there is the risk that commercial firms could fail because of insufficient funds to complete the necessary demonstrations of their technology.

Molten carbonate systems offer the most attractive near-term opportunities for utility applications. For the long-term, there is some risk that the MCFC manufactured cost will not decrease to the levels needed for widespread use in distributed generation and in coal-based IGFC systems. Independent studies of MCFC manufacturing methods, however, show that stack costs similar to combustion turbines (i.e., $250/kW) are possible in production quantities of 300 to 400 MW per year (EPRI, 1992b). Manufacturing costs now are about 10 times

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

higher—partly because manufacturing facilities are still about 100 times smaller. Studies indicate that the balance of plant costs will exceed the stack costs in commercial fuel cell power plants. A systematic market-entry program is the key to overcoming the high-cost, low-volume hurdle of new technologies.

For applications with coal, contamination of the fuel cell by trace coal constituents is the primary area of concern. Substances such as chlorides, sulfides, arsenic, alkali metals, zinc, cadmium, lead, and mercury vapors are capable of poisoning fuel cells and reducing their performance. At present, there is little information on the acceptable levels of these contaminants. High-temperature purification systems that can reduce some trace contaminants to very low levels are under development (Pigeaud, 1994).

Current Programs

DOE's program goals for IGFC systems are presented in Table 7-4. The FY 1994 budget authorization for fuel cells RD&D—which is now in the natural gas program—was $51.8 million. DOE is supporting technology and demonstrations of MCFC by two manufacturers at approximately $30 million/year, with EPRI and GRI collaborating at approximately $5 million/year each. One application is a 2-MW plant for the Santa Clara, California municipal electric utility grid; the other is a 250-kW pilot plant at Unocal's research center. Both demonstrations are expected to begin operation in the first half of 1995.

EPRI also has been sponsoring testing of a 20-kW MCFC stack on a coal-gas slipstream at the 160-MW Destec IGCC plant in Plaquemine, Louisiana, since late 1993. To date, this test has shown no indication that coal-derived gas presents any difficulty in use. However, long-term data remain to be collected.

DOE is supporting SOFC R&D at approximately $18 million per year, with EPRI and GRI each contributing approximately $1 million/year. For the tubular SOFC, the effort is focused on scale-up and demonstration. For the planar SOFC, the emphasis is on fundamental materials and manufacturing issues at a number of industrial, specialty research, and academic organizations. No prototype or commercial-scale plants are envisioned for three to four years for the planar SOFC. Many cost and manufacturing issues remain to be resolved in this time period.

While both the MCFC and SOFC systems ultimately will operate on gasified coal, at this time there are no commercial-scale or demonstration projects of coal-based IGFC.

Findings

The current U.S. fuel cell program is focused on the use of natural gas, although IGFC systems running on coal-derived fuel gas are envisioned by DOE as a logical follow-on. Such systems offer the highest efficiency and lowest emissions of coal-based technologies, but their cost currently is high. The initial demonstration of MCFC projects by two manufacturers is under way at the 250-

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

kW and 2-MW scales using natural gas. However, it is not likely that these demonstrations will be capable of resolving all technical issues.

At a reasonable rate of growth in demand for fuel cells, manufacturing costs for MCFC stacks could drop an order of magnitude to the $250/kW range. A systematic market entry program is the key to overcoming the high-cost, low-volume hurdle. Therefore, planned DOE support of balance of plant cost reduction development is the logical next step in fuel cell technology development, since these costs are larger than the fuel cell stack costs.

Future development of coal-based IGFC systems will depend on the success of current gas-based technology and on the resolution of key technical issues, particularly the types and levels of contaminants in coal-derived fuel gas that must be controlled.

MAGNETOHYDRODYNAMIC POWER GENERATION

Background

MHD (Magnetohydrodynamic) power generation is a method for converting thermal energy directly to electric power. The MHD generator is based on the concept of using a flowing ionized gas or liquid metal heated by fossil and/or nuclear fuel as the moving conductor in an electric generator. By using this very high-temperature (typically 2300 °C [4170 °F]) working fluid directly, the MHD generator serves as a topping cycle that achieves high overall efficiency (60 percent or more) when combined with additional power generation from a steam cycle fueled by the hot exhaust gas.

The simplest MHD generator is based on a linear geometry—the hot combustion gas flows through a linear duct or channel. A magnetic field provided by high-strength electromagnets at right angles to the gas flow induces an electric field at right angles to both the gas flow and magnetic fields. A "seed" material such as sodium or potassium is added to the combustion gas to improve its electrical conductivity. If electrodes are then placed on either side of the channel and connected through an external electrical load or resistance, current will flow through the gas, electrodes, and external load, providing power. In addition to MHD systems based on the flow of high-temperature seeded combustion gases, other proposed schemes for MHD power generation employ flows of liquid metals, combinations of liquid metals with gas bubbles, and alkali-seeded noble gases (or pure nitrogen or hydrogen) that ionize at much lower temperatures than do combustion gases (Angrist, 1976).

State of the Art

Most of the development work on MHD power generation has been on open-cycle combustion gas systems. These projects received significant funding in the United States (from DOE) and in the former U.S.S.R. Both projects have now

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

been closed down. In the U.S.S.R. a 25-MW natural-gas-fired system (U-25) provided electricity to the Moscow power grid for several years. The DOE concentrated on smaller-scale coal-fired systems, which included tests of over 2,000 hours on the lower-temperature heat recovery systems. The proof-of-concept high-temperature combustion and MHD generator sections were run for only about 400 hours. While most of the test performance goals were reached, the long-term high-temperature component durability required for utility applications is still in question. A proposal to DOE's CCT program to scale up to a combined MHD-steam plant of about 75 MW with an efficiency of approximately 31 percent was not selected for funding. Work on a tall-loop liquid metal MHD cycle has been concentrated in Israel, where test loops have been built to prove out the concept. These systems have the potential of 45 percent efficiency, but funding for further development is uncertain.

Technical Issues, Risks, and Opportunities

The open-cycle combustion gas systems as tested would extrapolate to a 500-MW coal-fired MHD plant meeting the federal NSPS for SO2 and NOx with an efficiency of up to 45 percent (Lohrasbi et al., 1991). This efficiency potential would drop considerably for smaller power plants. A claimed potential efficiency of 60 percent could only be met with the development of a high-temperature heat exchanger to preheat the combustion air to over 1370 °C (2500 °F), but little development work has been done on this exchanger. Furthermore, economic operation would depend on low-cost seed recovery, but only preliminary work has been accomplished in this area. The durability of the high-temperature MHD channel has not yet been demonstrated, and an integrated plant has not operated at any scale. Relative to other advanced technologies now under development, MHD systems pose much greater technological challenges because of the aggressive thermal environment and system complexity. At the same time, the thermal efficiency advantage of MHD systems has been eroded by more recent developments in other coal-based systems employing advanced gas turbines, fuel cells, and gasifiers.

Current Programs

DOE funding of the MHD proof-of-concept facility ended in FY 1993. FY 1994 funding and that requested for FY 1995 are only for site restoration, and no large-scale follow-on work is planned.

Findings

While a number of important technical goals were met by the DOE MHD program, significant issues were left unresolved, notably operational reliability.

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

No U.S. funding is planned to resolve these remaining issues, since other advanced power systems now offer comparable or superior performance with higher reliability, lower projected cost, lower emissions, and a much lower level of technical risk.

COMBUSTION TURBINES

Background

The combustion turbine is the key power generation component in most advanced coal-based systems. The turbine system consists of a compressor to take combustion air from atmospheric pressure to a pressure of 8 to 16 atmospheres; a combustor burning a fossil fuel (natural gas, light refined petroleum fractions, or coal-derived fuel gas) to produce hot combustion gases; and an expansion turbine to extract work as the high-temperature, high-pressure gas is reduced to ambient conditions. This system is referred to as the Brayton cycle. About two-thirds of the shaft work of the expansion turbine drives the compressor, and the remainder drives a generator to produce electricity. The net power output depends strongly on the turbine inlet temperature, which is limited primarily by materials considerations. Combustion turbines can be designed to burn any of the above-mentioned fuels (provided they are adequately free of contaminants) and to switch from one fuel to another in service.

Two types of combustion turbines are used for electric power generation, namely, heavy-frame and aeroderivative turbines, the latter derived from jet engine technology. Historically, major evolutionary improvements in aircraft jet engine technology have been adapted to heavy-frame utility combustion turbines. In addition, utilities have used aeroderivative combustion turbines for smaller-capacity generation applications. Thus, forecasting the evolution of combustion turbines for power generation is a relatively straightforward matter of assessing current jet airplane engine technology.

State of the Art

Current commercial gas turbine systems offered by U.S. and foreign manufacturers achieve firing temperatures up to 1300 °C (2350 °F), with unit sizes up to about 250 MW. Natural gas and light petroleum liquids are the fuels currently employed for power generation, typically for peak or intermediate loads. The simplest, lowest-cost-per-kilowatt, fossil power plant for peaking duty is the simple Brayton cycle combustion turbine described above. Both aeroderivative and heavy-frame turbines are used this way. Aeroderivative turbines are more efficient in simple-cycle operation because jet aircraft engines are intended to extract maximum energy from the hot combustion gases during the turbo-expansion.

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

TABLE 7-7 Characteristics of Natural-Gas-Fired Heavy-Frame, and Aeroderivative Combustion Turbine Power Plants

Turbine-Type

Simple-Cycle

Combined-Cycle

Heavy-frame

140-160 MW 34% efficiency

200-250 MW 50% efficiency

Aeroderivative

25-45 MW 36% efficiency

35-55 MW 47% efficiency

 

Source: Preston (1992).

A combined-cycle combustion turbine plant, in which a Brayton cycle gas turbine is combined with a Rankine cycle steam generator using the waste heat in the exhaust from the turboexpander, is the most efficient system for a fossil power plant commercially available today. Because relatively little useful energy remains in the expander exhaust of an aeroderivative combustion turbine, the heavy-frame machine has the higher efficiency in combined-cycle operation. Table 7-7 compares the capacities and thermal-to-electric energy efficiency typical of 1300 °C-class (2350 °F-class), heavy-frame, and aeroderivative combustion turbines burning natural gas being sold now or expected for delivery in the mid-1990s.

If the feed gas has been cleaned to a level that will meet air quality standards, oxides of nitrogen (NOx) are the only emission concern for combustion turbine power generation. Gas turbine manufacturers have developed dry (no water or steam injection) premixed lean-burn low-NOx combustors for commercially available gas turbines to achieve NOx levels of 7 to 25 ppm in the exhaust. As noted earlier (Chapter 3), such levels are required to comply with various state and local regulations, which are far more stringent than the federal NSPS of 75 ppm for gas turbines. Some of the first-generation dry low-NOx systems, however, are not so effective if operating at low load. Steam injection is another approach used to lower NOx and simultaneously augment power output by putting more mass through the turboexpander.

Continued evolution of gas turbines is projected with firing temperatures up to 1430 °C (2600 °F). These machines will require further cooling advancements, NOx reduction improvements, and probably ceramic nozzles and blades in the hottest sections of the hot gas path. The major combustion turbine manufacturers are forecasting commercial availability of such machines (using natural gas) in the 1998 to 2000 timeframe.

Technical Issues, Risks, and Opportunities

Ongoing and future technology improvements can further increase economic application of combustion turbines and broaden the attractiveness of coal utiliza-

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

tion in advanced power systems. At this time, however, most of the technical issues and opportunities in gas turbine development remain focused on the use of natural gas. Cleaner fuels and combustion air to keep out corrosive agents, materials to resist corrosion at higher turbine operating temperatures, more sophisticated blade cooling methods (closed-circuit steam cooling, partial cooling of the last-stage blades), and designs for reduced maintenance all will increase reliability over current combustion turbine models and are expected to push combined-cycle efficiencies on natural gas to 53 percent (HHV) or higher by the end of the decade and to 57 percent no later than 2010.

Advancements in hot section cooling designs, construction materials, coatings for oxidation and corrosion resistance, and thermal barrier coatings (see Chapter 9) will be key to increasing combustion turbine firing temperatures and thus further increasing the efficiency of combustion turbines and associated coal-based power generation cycles. Single-crystal alloys—already used in aircraft engines—could advance last-stage turboexpander blading design and thus improve combined-cycle efficiency. A major uncertainty for coal-based applications is the level of fuel gas cleanup needed to protect such advanced turbine designs.

Other technical issues facing application of combustion turbines in advanced coal-based power generation include

  • use of medium- and low-Btu fuel gas in combustors, and the effect of gas composition and variability on combustion efficiency and emissions;
  • corrosion and/or deposition on turbine blades;
  • integration of coal gasification with novel combustion turbine thermodynamic cycles; and
  • potential for catalytic combustion (low NOx) technology using coal syngas.

Many of these issues are being addressed in the ongoing programs described below. For example, recently reported work at General Electric Company, sponsored by EPRI and DOE, has confirmed that the combustion of coal gas with heating values below 100 Btu/scf is stable with very low CO emissions if the volumetric ratio of hydrogen to carbon monoxide exceeds unity. NOx emissions are also significantly below current standards. Control of NOx emissions from advanced turbines achieving higher firing temperature (and thus producing higher thermal NOx in air-blown systems) will require further study to determine whether future standards can be met by combustion controls alone or if additional requirements for postcombustion controls will be required.

DOE programs have investigated the corrosion potential of alkali metals on gas turbine blades in both PFBC and IGCC systems. In lower-temperature systems below about 870 °C (1600 °F), little damage has been observed. At higher temperatures, there has been some experimental evidence that fine mineral matter components carried along in the gas-phase interact with vapor-phase alkalis to

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

form innocuous solids that do not attack the turbine blades. If the problem turns out to be more severe, blade coating has been identified as the most promising approach for current designs. For higher-temperature advanced turbines (e.g., 1430 °C [2600 °F]), requirements for contaminant removal from coal-derived fuel gas are not yet established.

Issues of system integration for coal-based power plants also remain to be addressed. At the present time, the concept of phased construction is widely viewed as a flexible strategy that can be a cost-effective way to transition the modest capital investment in a combustion turbine from peaking application to mid-load and eventually to baseload. However, there are significant technological and regulatory hurdles to overcome in such a conversion, which must be addressed. For example, a combustion turbine optimized for simple- or combined-cycle gas firing is not optimal for coal-based IGCC operation. Overall, converting to gasified coal lowers the net power plant efficiency by 5 to 10 percentage points—depending on gasifier and cleanup system design—relative to natural gas, primarily due to losses upstream of the turbine (Gilbert/Commonwealth, Inc., 1994).

Finally, turbine design modifications may be needed to take full advantage of integration issues that are unique to coal-based systems. For example, conceptually, integration of coal gasification with gas turbines that have been modified for operation on compressed humidified air from a storage reservoir have the potential to reduce gasification power plant costs by 20 percent. Another advantage to this cycle is that low-level waste heat energy can be reinjected into the cycle through the evaporation of hot water to humidify the high-pressure air. Expensive development efforts, however, will be required to modify existing aeroderivative turbines for this cycle. Systems studies are needed to identify the most promising options, as well as associated risks.

Current Programs

DOE's Advanced Turbine Systems (ATS) program—housed in the natural gas program of the Office of Fossil Energy—is a major effort to develop and design high-efficiency combined-cycle combustion turbines. The FY 1994 authorization for this program was $21.9 million; the FY 1995 DOE request has more than doubled to $44.9 million. The research is aimed at potential barrier issues, focusing on two primary areas: higher firing temperatures, mainly from improved cooling concepts and materials, and high-efficiency cycles, aimed at steam cooling, interstage compression cooling, and chemical recuperation. The program aims to provide technology ready for commercial baseload application by 2000 that will be applicable to coal and biomass systems as well as natural gas. DOE is also involved in other cooperative programs with industry, notably the Collaborative Advanced Gas Turbine program involving DOE, EPRI, GRI, and turbine manufacturers.

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

Increases in the firing temperatures of advanced gas turbines will occur as a result of competitive pressures among manufacturers with a very significant acceleration resulting from the DOE ATS program. The availability of those machines will significantly improve IGCC plant efficiencies, as discussed earlier in this chapter. The higher-temperature turbines will also utilize higher pressure ratios and be significantly larger. As a result, single-train IGCC plants will have outputs of 350 to 400 MW, which will lower specific plant costs through improved economies of scale.

As noted above, the General Electric Company has successfully tested combustion in a General Electric model 7F combustion turbine of a simulated coal-based syngas diluted with H20, CO2, and/or N2 to HHV (higher heating values) as low as 100 Btu/Scf. These heating values (which are nearly 10 times less than that of natural gas) are comparable to values from the low-Btu fuel gas produced by advanced air-blown coal gasifiers.

Findings

Combustion turbine technology will continue to advance rapidly, driven by aircraft technology improvements but also by power generation application needs. Continued combustion turbine technology improvements and advanced cycles development on natural gas also will benefit the economics of future coal-based systems such as IGCC, PFBC, and IFC designs.

With respect to coal-based applications, key issues and uncertainties include fuel gas cleanup requirements for advanced turbine designs and the design and integration of turbine systems that can optimally accommodate evolution from natural gas to coal gas firing. NOx emission control requirements and approaches for higher-temperature advanced turbines also remain to be resolved.

EMISSION CONTROL TECHNOLOGIES

Background

The development of environmental control technologies for electric power generation has primarily focused on the control of air emissions resulting from the combustion of fossil fuels. For coal-fired steam-electric generation, the emphasis has been on the control of particulate matter, sulfur dioxide (SO2), and nitrogen oxide (NOx) emissions—the three ''criteria" air pollutants subject to federal NSPS (see Chapter 3 and Appendix D).

Particulate emissions in coal-based systems arise primarily from coal ash entrained in the flue gas stream (flyash) and from chemical reagents added to control other pollutants, especially SO2. Control methods may employ inertial separation, wet scrubbing, electrostatic precipitation, or filtration to separate particles from the gas stream. The electrostatic precipitator (ESP) is the most widely

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
×

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,

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
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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-

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
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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

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
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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

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
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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

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
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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

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
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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

Suggested Citation:"7 ELECTRIC POWER GENERATION." National Research Council. 1995. Coal: Energy for the Future. Washington, DC: The National Academies Press. doi: 10.17226/4918.
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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.

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The U.S. Department of Energy (DOE) was given a mandate in the 1992 Energy Policy Act (EPACT) to pursue strategies in coal technology that promote a more competitive economy, a cleaner environment, and increased energy security.

Coal evaluates DOE's performance and recommends priorities in updating its coal program and responding to EPACT.

This volume provides a picture of likely future coal use and associated technology requirements through the year 2040. Based on near-, mid-, and long-term scenarios, the committee presents a framework for DOE to use in identifying R&D strategies and in making detailed assessments of specific programs.

Coal offers an overview of coal-related programs and recent budget trends and explores principal issues in future U.S. and foreign coal use.

The volume evaluates DOE Fossil Energy R&D programs in such key areas as electric power generation and conversion of coal to clean fuels.

Coal will be important to energy policymakers, executives in the power industry and related trade associations, environmental organizations, and researchers.

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