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--> 10 Conclusions and Recommendations This chapter synthesizes the discussions and findings of Part II (chapters 5-9) in the context of the committee's charge and the strategic planning framework and background presented in Part I (chapters 1-4). For each topic discussed in chapters 4 through 9, conclusions and recommendations are offered below.1 The cross-cutting systems analysis area not explicitly covered in chapters 4 through 9 is addressed separately. In the final section of the chapter, the committee's conclusions and recommendations are interpreted in the context of the individual sections of the EPACT that relate to coal (see Chapter 1 and Appendix B). STRATEGIC PLANNING FOR COAL In Chapter 4 a strategic planning framework was established to assess planning for coal-related RDD&C. The framework is based on projected scenarios for future energy demand and markets for coal technologies, taking into account likely future environmental requirements, competing energy sources, institutional issues, international activities, and other factors affecting the demand for coal. In the committee's view, the overall objective of DOE's coal program should be to provide the basis for technological solutions to likely future demands, as reflected in the scenarios. The committee defined three planning horizons—near-term (1995-2005), mid-term (2006-2020), and long-term (2021-2040) periods—for which the scenarios were formulated and requirements for coal were outlined. Based on its analysis, the committee concluded that coal will continue to be a major energy source in the U.S. economy over all planning horizons considered 1 Asterisks (*) identify the most important recommendations.
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--> and that a sustained program of RDD&C for coal technologies is important for the economic, environmental, and security interests of the United States. The strategic planning framework identified two priority areas for the DOE coal program: (1) conversion of coal to electricity, representing the principal market for coal for all planning periods, but particularly in the mid- to long-term periods; and (2) conversion of coal to liquid and low- and medium-Btu gaseous fuels, in the mid to long-term. EPACT requirements for coal use emphasize the need for high-efficiency, low environmental impacts, and competitive costs. These needs are generally consistent with DOE's objectives for coal RDD&C, as defined in the most recent planning documents (DOE, 1993a, 1994a). The DOE planning horizon, however, currently extends only to 2010. Specific objectives have been formulated for that period for advanced power systems and advanced fuel systems. These objectives are discussed below in the sections on electric power generation and clean fuels from coal. Conclusions DOE's strategic planning objectives for coal technology RDD&C currently extend only through the year 2010, even though coal will continue to be a major source of energy well beyond that period. The most important strategic objectives for coal RDD&C programs are to support the development of (a) advanced coal-based electric power systems that are considerably more efficient and cleaner than current commercial systems and which will be needed beginning in the near to mid-term; and (b) advanced coal-based fuel and coproduct systems that can be used to replace conventional oil and gas in the mid- to long-term periods. Recommendations2 *The planning horizon for DOE coal RDD&C programs should extend beyond the agency's current planning horizon of 2010. The committee recommends the use of three time periods for strategic planning: near-term (1995-2005), mid-term (2006-2020), and long-term (2021-2040). The main objective of DOE's coal program in all periods should be to provide the basis for technological solutions to likely future demands in a way that is robust and flexible. COAL PREPARATION, COAL-LIQUID MIXTURES, AND COALBED METHANE RECOVERY Coal preparation—or cleaning—is a widely used commercial process for removing mineral matter from as-mined coal to produce a higher-quality product. 2 Asterisks (*) identify the most important recommendations.
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--> Current physical cleaning processes are used primarily to reduce the ash content of as-delivered coal, although some sulfur reduction (typically 20 to 30 percent) is also achievable in coals with high pyrite content. Because coal is an abundant and relatively low-cost fuel, the incremental cost of coal cleaning is a major factor limiting the degree of impurity reductions that are economically feasible. DOE research in recent years has focused on advanced processes to clean fine coal fractions to achieve a relatively low ash, low-sulfur product suitable primarily for premium applications, such as the production of coal-liquid mixtures that can be substituted for petroleum-based fuels. More recently, attention has also focused on the potential for coal cleaning to remove trace species as a means of reducing power plant emissions of air toxics. A series of RD&D goals has been defined (DOE, 1993a). Coal-liquid mixtures or slurries—primarily coal-oil and coal-water fuels—are another commercial technology that allows coal to be substituted for liquid fuels in combustion applications. R&D in this area peaked during the late 1970s and early 1980s when oil prices were high and coal-based substitutes were attractive. Commercial interest waned, however, as oil prices declined and oil price projections remained stable. Nonetheless, DOE has continued to fund basic and applied research related to CWSs (coal-water slurries), primarily at universities. Finally, interest in recovery of coalbed methane has been stimulated by concern about greenhouse gases and EPACT requirements. Methane recovery technology for high methane concentrations is commercially available, and recovery is practiced by the gas and coal mining industries where local conditions justify the investment. However, systems for the capture and use of dilute coalbed methane streams, which are found in many coal mining operations, are not sufficiently mature for commercial implementation. As noted in Chapter 3, increased efforts will likely be needed to reduce coalbed methane released from underground mining, in accordance with the Climate Change Action Plan (Clinton and Gore, 1993). The research challenge is to economically recover coalbed methane from very dilute gas streams. Conclusions Coal preparation is a highly developed, commercially available technology that is widely used in the coal industry but that offers only limited opportunities for R&D to significantly lower the cost of advanced coal preparation processes. Continued research with extensive industry participation should achieve further improvements in existing and emerging technologies. There may be opportunities through sustained fundamental research on cleaning processes to improve the environmental acceptability of coal. Given the mature status of technologies for the production and use of coal-liquid mixtures and the very limited market for these mixtures, no further development by DOE appears necessary.
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--> Although the collection and use of concentrated coalbed methane streams are not widely practiced in the coal mining industry, relevant technologies are available for commercial application. Additional reductions in emissions of coalbed methane could be achieved through the development of technologies for the capture and use, or destruction, of dilute coalbed methane streams. Recommendations Strategic planning goals for the performance and cost of coal cleaning processes should define clearly the supporting role of coal preparation in DOE's programs in advanced power generation and fuels production, thereby focusing R&D activities. DOE should phase out program activities related to coal-liquid mixtures. DOE should implement a technology R&D program that addresses the control and use of dilute coalbed methane gas streams in response to EPACT requirements. ELECTRIC POWER GENERATION Power Generation Systems The availability of high-performance gas turbines and low-cost natural gas has resulted in the use of natural-gas-fired combustion turbines for many recently installed power generation facilities. As discussed in Chapters 3 and 4, decreasing availability and higher costs for natural gas in the next decade and beyond are expected to result in a resurgence of construction and repowering of coal-based power generation facilities, with requirements for greatly improved emission controls and higher efficiency. Substantial improvements over past practices are technically possible. A large fraction of DOE RDD&C on power generation is devoted to systems designed to meet anticipated emission control and efficiency requirements. The advanced coal-based power generation systems under development with DOE funding can be divided into three groups based on projected efficiency:3 Group 1—approximately 40 percent efficiency—includes the low-emission boiler system (LEBS), first-generation PFBC (PFBC-1), and first-generation IGCC (IGCC-1). Group 2—approximately 45 percent efficiency—includes EFCC, second-generation PFBC (PFBC-2), and second-generation IGCC (IGCC-2). Group 3—50 to 60 percent or greater efficiency—includes HIPPS, improved second-generation PFBC (improved PFBC-2), integrated gasification advanced-cycle (IGAC), and IGFC. 3 For definitions of thermal efficiency, see Glossary.
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--> Important features of these systems are summarized in Table 10-1. Information on state-of-the-art commercial pulverized coal systems is included in the table as a baseline. Current DOE funding levels for these various technologies were summarized in Chapters 2 and 7. Efficiency and Cost Targets As shown in Table 10-1, DOE's efficiency goals for advanced power systems rise to 60 percent for the year 2010 (best current new plant levels are about 38 percent for the United States and 42 percent worldwide). In the DOE plan the highest efficiencies are expected to be achieved with IGFC technology (DOE, 1993a). A number of other systems are projected to achieve efficiencies of 45 to 55 percent using advanced combustion and gasification-based approaches and high-performance gas turbines. A major objective of the DOE plan is to achieve these higher efficiencies at an overall cost of electricity that is 10 to 20 percent lower than that of today's coal-fired power plants while also meeting more stringent environmental requirements (see Table 10-2).4 In the view of the committee, the DOE efficiency goals, especially for the later years, are quite optimistic. For example, the efficiency goals of 55 percent for systems using 1290 °C (2350 °F) gas turbine topping cycles exceed the performance capabilities of about 50 percent efficiency for current combined-cycle systems using natural gas. While turbine improvements are expected to raise the efficiency on natural gas to about 57 percent (see Chapter 7), coal gasification and gas cleanup energy losses will decrease efficiency by five to 10 efficiency points when using the gasification systems being demonstrated in the CCT program (see Chapter 6). Thus, substantial reduction of gasification-related losses is needed to achieve the DOE target system efficiency with IGCC. As noted in Chapter 7, the hybrid second-generation pressurized fluidized-bed combustion system, which gasifies only part of the coal, is estimated to have a potential for approximately four percentage points higher efficiency than IGCC systems where all the coal is gasified (Maude, 1993). Conceivably, this system could achieve the DOE efficiency goal; however, substantial technical hurdles remain to be overcome. Similar comments apply to the 60 percent efficiency goal for IGFC systems. The goal of 10 to 20 percent reduction in the cost of power, concurrent with significant efficiency increases and emissions reductions, may be especially difficult to realize. For example, roughly 30 percent of the cost of electricity today for a new coal-fired plant represents the cost of fuel (EPRI, 1993). Thus, reducing fuel requirements by one-third by raising plant efficiency from about 40 to 60 percent would lower the overall electricity cost by about 10 percent, which is DOE's minimum cost reduction objective. A smaller efficiency gain would yield 4 Identical to Table 2-3.
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--> TABLE 10-1 Advanced Coal-Based Power Systems Supported by DOE Technology (target year for commercial design) Design Efficiency (percent) Coal Conversion Components Power Generation Components Particulate Control System SO2 Control System NOx Control System New pulverized coal (commercial baseline) 38-42 Supercritical boiler 3,500 to 4,500 psi steam turbine ESP or fabric filter Wet lime or limestone FGD Low NOx burners + SCR GROUP 1 SYSTEMS LEBS (2000) 42 Supercritical boiler 4,500 psi steam turbine Advanced flue gas cleanup + combustion controlsa PFBC-1 (2003) -40 Bubbling and circulating bed PFBC units 1,800 psi steam turbine + gas turbine Cyclones + fabric filter In-bed limestone or dolomite Combustion controls IGCC-1 (1997) -40 O2-blown entrained- bed gasifiers 2350°F gas turbine +HRSG/turbine Cold gas quenching Cold gas H2S absorption Cold gas cleanup + steam injection GROUP 2 SYSTEMS EFCC (1997) 45 Slagging combustor + 2300°F heat exchanger 2350°F gas turbine + HRSG/turbine Fabric filter Wet FGD Combustion controls (+ SCR if needed) PFBC-2 (2005) 45 Circulating PFBC + coal pyrolyzer 2350°F gas turbine + 2,400 psi steam turbine Hot gas filtration In-bed limestone or dolomite Combustion controls (+ SCR if needed) IGCC-2 (2002) 45 Oxygen- or air-blown fluidized- bed gasifier 2350°F or 2500+ ºF gas turbine + HRSG/turbine Hot gas filtration Hot gas desulfurization + in-bed limestone (optional) Combustion controls(+ SCR if needed)
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--> GROUP 3 SYSTEMS HIPPS (2003) 50 High-temperature advanced furnace 2500 °F gas turbine + HRSG/turbine (+ auxiliary fuel if needed) Advanced flue gas cleanup system + in-furnace controlsa Improved PFBC-2 (2010) ≥50 Circulating PFBC + coal pyrolyzer 2600 °F turbine + 4,500 psi steam turbine Hot gas filtration In-bed limestone or dolomite Combustion controls (+ SCR if needed) IGAC (2010) ≥50 Oxygen- or air-blown fluidized-bed gasifier 2600 °F gas turbine (humidified) Hot gas filtration Hot gas desulfurization + in-bed limestone (optional) Combustion controls (+ SCR if needed) IGFC (2010) ≥60 Oxygen- or air-blown fluidized-bed gasifier Molten carbonate fuel cell (1200 °F) +HRSG/turbine Hot gas filtration Hot gas desulfurization + in-bed limestone (optional) Combustion controls (+ SCR if needed) HRSG, heat recovery steam generator. ESP, electrostatic precipitator. FGD, flue gas desulfurization. SCR, selective catalytic reduction. a Final system not yet selected.
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--> TABLE 10-2 Strategic Objectives of DOE's Advanced Power Systems Program Period Objective 2000 2005 2010 2015 Efficiency (%) 42 47 55 60 Emissions (NSPS)a 1/3 1/4 1/10 1/10 Cost of energy 10-20 percent lower than currently available pulverized coal technology a NSPS, New Source Performance Standards. Current federal standards apply to emissions of sulfur dioxide, oxides of nitrogen, and particulates from coal-based steam generators. Source: DOE (1993a). still smaller cost savings. These estimates assume that the nonfuel costs—principally the initial capital cost—remain constant. DOE targets show lower capital costs for advanced technologies than current commercial systems. More likely, the capital cost of more efficient combined-cycle systems will exceed that of the simpler, less demanding technologies now in use (Merrow et al., 1981). Higher capital and operating costs would mean that overall reductions in the cost of electricity would be difficult or impossible to achieve. While projections of the cost and performance of new technologies are subject to great uncertainty (Frey et al., 1994), comparison of systems and options should be done on a common and clearly stated basis to provide valuable guidance for investment in RDD&C (see below, Systems Analysis and Strategy Studies). Such comparative studies are extremely valuable for assessing the validity of program goals and for communication of results. A more realistic cost goal for the DOE advanced power systems program might be to achieve efficiency improvements at an overall electricity cost comparable to that for new coal plants today. For the future U.S. market, some cost premium could even be acceptable if justified by the improved environmental performance and reduced externality costs associated with advanced technologies. Indeed, future environmental regulations may well require such higher performance, creating new incentives for investment in higher-efficiency systems. To be competitive overseas, advanced technologies would require the lowest possible capital costs consistent with the environmental and other requirements of specific foreign markets. In short, despite DOE's current planning estimates, it remains to be seen whether high-performance and smaller investment costs are in fact compatible objectives. Group I Systems Group 1 power generation systems generally make use of commercially available components and technologies, such as supercritical boilers, gasifiers,
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--> and cold gas cleanup systems. Only limited use of first-generation PFBC and IGCC systems is expected in the United States. Demonstration programs for these technologies are under way both in the United States and abroad, and the main incentive to continue the domestic activity is to develop a foundation for second- and third-generation systems. On the other hand, the LEBS technology program outlined by DOE (1993a) does not appear to offer opportunities for development of a substantially more efficient, lower-emission system. Only if LEBS achieves a significantly lower cost than existing systems with comparable performance would its development be justified for near-term markets. Assuming that Group I performance and cost objectives can be met, the market for Group 1 technologies will probably be limited to near-term installations where there is no economic penalty for carbon dioxide (CO2) emissions. Although the committee's baseline scenarios assume no such penalties for the near-term (1995-2005), it envisions new regulations or penalties aimed at forcing CO2 reductions during the mid-term period (2006-2020). Technologies in Group 1, with their limited efficiency improvements over existing plants, would be at a disadvantage relative to the newer Group 2 systems emerging in the mid-term period. The ''less demanding" scenario discussed in Chapter 4 assumes that economic penalties on CO2 emissions might not be imposed for the foreseeable future. This might well be the case in developing countries such as China, and Group 1 technologies might therefore be of potential export interest. Group 2 and 3 Systems In contrast to Group 1 systems, technologies in groups 2 and 3 are judged by the committee to have greater potential to meet future power generation and associated environmental requirements: all technologies in these two groups make use of advanced components to achieve higher efficiencies and lower emissions. Major questions of system integration and reliability will need to be addressed, and early pioneer installations could serve as a basis for improved systems. The riskiest components appear to be the high-temperature heat exchanger and furnace required for the indirectly fired systems, and the hot gas cleanup systems for the advanced PFBC and gasification-based systems. It is not established that high-temperature gas turbines can tolerate the chlorine and alkali metals that may be present in FBC (fluidized-bed combustion) products or the sulfur and particulates in the gasifier products of IGCC systems. Although hot gas cleanup is a component of advanced IGCC systems, cold gas cleanup could still allow the technology to succeed, if at a lower efficiency. In this sense, IGCC is a somewhat less risky technology than PFBC. The 1370 °C to 1425 °C (2500 °F to 2600 °F) gas turbine required for Group 3 systems is within the state of the art for aviation systems but is still under development for electric power generation systems and will require demonstration and testing. The IGCC-2 and IGAC systems with an advanced gas turbine
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--> may not be significantly more expensive than first-generation systems if the turbine development effort is successful. As noted previously, integrated gasification fuel cell systems offer the highest efficiencies and emission controls. Systems using molten carbonate or solid oxide fuel cells incorporate a steam bottoming cycle to maximize efficiency. Molten carbonate and solid oxide fuel cells operate at high temperatures (650 °C [1200 °F] and 980 °C [1800 °F], respectively). Since the maximum voltage produced by a fuel cell decreases with increasing temperature, the higher-temperature solid oxide fuel cell produces a smaller fraction of the total system power. However, the potentially lower costs of the solid oxide fuel cell provide incentives for continued research on these systems. The potential market for fuel cell technologies is quite large, especially for distributed power generation. However, fuel cell systems may still not be cost competitive with gas turbine systems without environmental incentives for higher efficiencies. Gas turbine and fuel cell activities are currently funded under the natural gas portion of DOE's FE R&D program. However, gas turbines and fuel cells could be used with coal-derived gas, with the addition of gasification and gas cleanup facilities. The principal operating difference between natural gas and coal-derived fuel gas in these applications relates to the contaminants in coal-derived gas. Cold gas cleanup is capable of removing contaminants to a negligible level; however, there is an efficiency penalty of about two percentage points, along with the production of liquid waste streams that must be treated, adding to system complexity and cost. Hot gas cleanup is potentially more efficient but at the expense of less complete removal of contaminants, especially volatilized species that are not captured in current hot gas cleanup designs. The requirements for cleanup of coal-derived fuel gas are expected to differ for fuel cell and gas turbine systems. System optimization will be required and needs to be established as part of the DOE coal program. For the molten carbonate fuel cell, ammonia, hydrogen sulfide, chlorine compounds, trace metals, and particulates would interact with the electrodes and with the carbonate electrolyte, necessitating electrolyte replacement and disposal of resulting water-soluble solid waste. For high-temperature gas turbines, damage to the blades is of greatest concern, and a discussion of research aimed at mitigating this concern can be found in Chapter 9 (Advanced Research Programs). Degradation caused by contaminants would limit maximum turbine inlet temperature, thereby limiting attainable system efficiency. Thus, for fuel cell systems, the major development challenge is to reduce both fuel cell costs and balance-of-plant costs. For gas turbines, the major goal is to maximize turbine inlet temperature. Increasing turbine inlet temperature from the current maximum of 1290 °C (2350 °F), beyond the 1370 °C to 1425 °C (2500 °F to 2600 °F) proposed for integrated gasification advanced-cycle systems, to the 1540 °C to 1650 °C (2800 °F to 3000 °F) used in high-performance turbines would bring system efficiencies to a level approaching that expected for
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--> molten carbonate fuel cells. These major development goals for fuel cells and gas turbines apply to systems fueled with either natural gas or coal-generated gas. No special considerations for coal-derived fuel gas appear necessary at this time, beyond those described above for the coal program. To use coal, both fuel cell and gas turbine systems depend on coal gasification technology; both can accept methane and light hydrocarbons in the fuel gas. As discussed in Chapter 6, coal gasification results in a loss of five to 10 percentage points in overall power generation efficiency compared to natural gas. Development of maximally efficient gasification technology is thus essential for future high-efficiency utilization of coal for both fuel cell and gas turbine systems. Magnetohydrodynamics The use of topping cycles—as in fuel cells, gas turbines, and MHD generators—to achieve efficiencies higher than those attainable in the simple steam Rankine cycle (approximately 42 percent) has been adopted worldwide and is the major focus of the ongoing DOE program on advanced technologies for electricity generation. Advances in gas turbine and fuel cell technologies have essentially closed the original efficiency gap that stimulated a large worldwide effort on MHD during the 1960s and 1970s. Over the past decade, this MHD effort has been greatly reduced. Within the DOE FE Advanced Clean/Efficient Power Systems Program, no further funds are allocated for MHD, except for closeout of the proof-of-concept study. EPACT Section 1311 recommends (and the committee concurs) that an integrated documentation of the results of the extensive proof-of-concept work should be prepared, to capture the "lessons learned" and to establish a reference point for any possible development of MHD systems in the future. Emissions Control Technologies Environmental control requirements for coal-based power plants are expected to become increasingly stringent in response to more demanding federal, state, and local requirements. In the near-term, new control requirements for nitrogen oxides (NOx) and air toxics are anticipated, along with new ambient standards for fine particulates. Over the longer term, significant reductions in CO2 and solid wastes may be needed. Targets DOE's strategic objectives for conventional air pollutants (SO2, NOx, and particulates) express future goals relative to the 1979 federal New Source Performance Standards (NSPS) for coal-fired power plants (see Table 10-2). These emissions goals apply to advanced power systems in groups 2 and 3. DOE's goals
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--> EPACT Requirements Key Features of DOE Program Activities Committee Rating and Comments Section 1304: Nonfuel Use of Coalb Plan and carry out RDD&C program for nonfuel use of coal, including: - production of coke and other carbon-based products, chemicals, and chemical feedstocks from coal - chemicals from synthesis gas - utilization of wastes from coal (see Section 1308) Above program should include assessment of economic feasibility of coproduction, refining, and utilization of coal-based products (see Section 1305) Syngas production activity supports concept development for coproduction of coal-derived fuels and chemicals in conjunction with electric power (see Section 1312, indirect liquefaction). Mild gasification/coal refinery activities address production of coke and chemical intermediates (see also Sections 1305 and 1312). See Section 1312 Low priority for DOE Decreasing market for coke CCT program on mild gasification adequate (see Section 1305) DOE supporting Carbon Products Consortium in development of coal-based alternative feedstocks and establishment of links with industry. No further funding requested for FY 1995. Low priority for DOE Section 1305: Coal Refinery Program Conduct RDD&C program for coal refining technologies for high-sulfur coals, low-sulfur coals, subbituminous coals, and lignites to produce transportation fuels, compliance boiler fuels, fuel additives, lubricants, and chemical feedstocks, alone or with power generation. Coal refinery activity included under advanced clean fuels research (Section 1312) addresses coproduction of electricity and coal liquids. High priority for DOE Worthwhile concept; systems assessments have indicated promising areas, especially coproduction of syngas liquids with electricity. Further assessments needed to identify and exploit opportunities. Mild gasification is part of ongoing CCT program. Low priority for DOE Adequately covered by CCT program.
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--> Section 1306: Coalbed Methane Recovery Conduct a study of barriers and environmental safety aspects. Disseminate information to public on state-of-the- art technologies. Conduct coalbed methane demonstration and commercial application program Previous DOE program ended in 1993. Clinton administration's Climate Change Action Plan (CCAP) establishes new initiatives to reduce methane emissions from all major sources, including coal mines (Clinton and Gore, 1993). DOE FY 1994 budget request for $300K for coalbed methane activities was not approved; FY1995 budget request covers coalbed methane recovery under natural gas program. CCAP requires DOE and EPA to create Coalbed Methane Outreach program-currently no activity due to lack of funding. CCAP requires expansion of DOE RD&D programs for methane recovery from coal mining; interaction with stakeholders initiated in 1993 continues. Low methane concentration (81.0%) Moderate priority for DOE There are possible low-level R&D activities investigating separation and combustion processes for dilute methane. Higher methane concentrations Low priority for DOE Existing commercial technology adequate but in limited use. Section 1307: Metallurgical Coal Development Establish RDD&C program for use of metallurgical coal as: - a boiler fuel - an ingredient in steel manufacture - source of coalbed methane DOE not currently conducting any research specific to metallurgical coal development. Information on gas content in 16 U.S. coal basins available in METC database. Commercial technology exists to burn metallurgical coal as boiler fuel or use in steelmaking. Low priority for DOE—inactive No new technology needed to burn as boiler fuel. Activities relating to metallurgical coal as a source of coalbed methane should be included in Section 1306 programs.
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--> EPACT Requirements Key Features of DOE Program Activities Committee Rating and Comments Section 1308: Utilization of Coal Wastes Establish RDD&C program for utilization of coal wastes from mining and processing, including as a boiler fuel. AR&ET program on waste management includes examination of technical and economic aspects of waste utilization technology Low priority for DOE—inactive Technology is commercial-possible limited DOE role in economic and technical assessment. Application of past DOE work on fluidized-bed combustion now being handled by industry. Section 1309: Underground Coal Gasification Conduct RDD&C program for in situ conversion of coal to an easily transportable gaseous fuel. DOE program ended in FY 1991. Sufficient technical, operational, and environmental parameters developed to allow industry to make necessary decisions regarding commercialization. Low priority for DOE—inactive In agreement with current DOE assessment that underground gasification will not result in a competitive gaseous fuel. Section 1310: Low-Rank Coal Research and Development Pursue R&D program to expand use of low-rank coals in high-value-added carbon products, fuel cells, coal-water fuels, distillates, and other niche market applications. Research effort on low-rank coals sponsored by DOE at University of North Dakota Energy and Environmental Research Center (UNDEERC). Consortium being formed under UNDEERC leadership to demonstrate production of low-rank coal water fuels from Alaskan coals. No special effort required aimed at low- rank coals Low-rank coals are included in general coal utilization program (Section 1301) and represent one end of a continuum of materials.
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--> Section 1311: Magnetohydrodynamics (MHD) Carry out RDD&C program to determine adequacy of engineering and design information completed to date under DOE sponsorship. Issue solicitations to fulfill above objective. Conducting proof-of-concept program closeout No solicitations issued Documentation and cleanup activities—high priority for DOE Need for thorough documentation of past work: current plans for this activity insufficient. MHD system development—low priority for DOE MHD does not appear to offer significant advantages over other advanced high-efficiency systems. Next step in development involves very expensive demonstration program, since technical risk cannot be broken down. Section 1312: Oil Substitution Through Coal Liquefactionc Conduct RDD&C program to develop economically and environmentally acceptable advanced technologies for oil substitution through coal liquefaction. Program goals are to include: - improved resource selection and product quality - increased net yield - increased overall thermal efficiency - reduced capital and operating costs Direct liquefaction, including advanced liquefaction processes, coprocessing with waste materials, and innovative process concepts High priority for DOE DOE should maintain an active program since industry activity in this area is declining. Innovative approaches should be encouraged. Large pilot and demonstration plants not required at this time.
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--> EPACT Requirements Key Features of DOE Program Activities Committee Rating and Comments Indirect liquefaction, including Fischer-Tropsch chemistry, catalyst development, reactor design, oxygenate catalyst research, syngas, and low-cost hydrogen production High priority for DOE Opportunities for coproduction with electricity (see Section 1305). Need coordination with active industry programs for natural gas conversion; DOE should focus on applying this technology to coal. Mild gasification/coal refinery activity, including systems for coproducts (overlap with Section 1305) See Section 1305 TITLE XIII-COAL Subtitle B-Clean Coal Technology Program Section 1321: Additional Clean Coal Technology Solicitations Conduct additional solicitations for development of cost-effective, higher-efficiency, low-emission coal utilization technologies, with emphasis on need for commercialization by 2010. In response to request from Secretary for Energy, the National Coal Council prepared a report (NCC, 1994) addressing future directions for the CCT program. DOE report, Clean Coal Technology—Completing the Mission, released 05/06/94 (DOE, 1994c). No additional solicitations issued beyond CCT-V. Proposed diversion of CCT funds to overseas demonstration projects. High priority for DOE—future action requires consideration (see text for discussion) Emphasis should be on deployment of technologies developed and demonstrated in earlier rounds. Commercial acceptance of CCT technologies may require further cost sharing of technical and financial risk.
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--> TITLE XIII-COAL Subtitle C-Other Coal Provisions Section 1332: Innovative Clean Coal Technology Transfer Program Develop joint DOE/Agency for International Development clean coal technology transfer program to encourage exports of U.S. technologies that allow more efficient, cost-effective, and environmentally acceptable use of coal resources. Solicitations for China and Eastern Europe ''showcase" projects to be outlined in FY 1994. Public meeting on Clean Coal International Technology Transfer Program held February 1994. NCC report (see Section 1321) includes advice on conducting international technology transfer effort. Low priority for DOE compared to domestic program Current funds probably insufficient to meet requirements of Sections 1321 and 1332. Priority should be given to Section 1321 requirements emphasizing CCT deployment in domestic market. Section 1336: Coal Fuel Mixtures Prepare a report on technical and economic feasibility, development status, market potential, and commercialization barriers to combining coal with other materials, such as oil and water fuel mixtures. Coal preparation program (Advanced Clean Fuels Research) includes superclean coal water slurry (SCCWS) project (formerly part of Alternative Fuels Program). Low priority for DOE—previous assessments adequate Technologies for this very specialized market have been effectively commercialized and utilized. Section 1337: National Clearinghouse Assess feasibility of establishing national clearinghouse for exchange and dissemination of information on technology relating to coal and coal-derived fuels. No current DOE activities; DOE is awaiting recommendations from National Research Council. Need for national clearinghouse should be established by market survey of potential users. Any activity should involve participants from inside and outside DOE. External committee should assess feasibility of concept and make recommendations for implementation.
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--> EPACT Requirements Key Features of DOE Program Activities Committee Rating and Comments TITLE XX—GENERAL PROVISIONS; REDUCTION OF OIL VULNERABILITY Subtitle A—Oil and Gas Supply Enhancement Section 2013: Natural Gas Supply Conduct five-year program to increase recoverable natural gas resource base by more intensive recovery from discovered conventional resources; extraction from unconventional sources; surface gasification of coal; and recovery of methane from biofuels. Conduct five-year program on cofiring of natural gas with coal in utility and large industrial boilers. METC Surface Coal Gasification Program involves R&D on new concepts development and refinement of existing systems. Methanation aspect of SNG production—low priority for DOE Gasification—high priority for DOE (see Section 1301) Cofiring of natural gas with coal addressed in CCT program. Low priority for DOE—appropriate level of effort Established technology for pulverized coal CCT program activity adequate. a This summary of DOE program activities is based on planning documents provided by DOE's Office of Fossil Energy, the DOE FY 1994 budget, the FY 1995 congressional budget request, and presentations to the committee by DOE staff (see Appendix F). b The committee notes that DOE programs responding to Section 1304 include fuel and nonfuel uses of coal. C See also committee ratings and comments on advanced clean fuels research under Section 1301.
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--> for such an activity should be established by a market survey of potential users prior to significant investment of resources. In comparing all the activities within DOE's current coal program and those mandated by EPACT, the committee noted a significant discrepancy in priorities. The current DOE program focuses on relatively near-term activities, notably the development, demonstration, and commercialization of coal-based power generation systems by 2010, at the expense of longer-term research programs. Such longer-term programs would position the United States to respond to future energy scenarios in which coal assumes increasing importance for uses other than power generation. In contrast to the DOE approach, the coal-related provisions of EPACT endorse the development of a longer-term, more balanced spectrum of coal-based technologies. The committee's recommendation that strategic planning for coal should address requirements for periods to the middle of the next century is more consistent with the EPACT approach than with DOE's current priorities. Conclusions The current DOE program is appropriate and responsive to EPACT sections related to coal-based electric power generation. EPACT places significant emphasis on programs related to the expansion of coal use for manufacture of liquid and gaseous fuels and specialty products. The DOE program covering uses of coal beyond power generation has decreased in recent years. The need for a national clearinghouse to exchange and disseminate data on coal technologies has not yet been established. Recommendations15 There should be increased DOE support of fundamental and applied research aimed at longer-term uses of coal (2006-2040) to balance decreased industry research, guarantee the maintenance of U.S. technological expertise in this area, and position the United States to respond to future energy needs. *Within the DOE coal program there should be an increasing emphasis on the production of clean fuels and other carbon-based products over time. No further action should be taken to establish a national clearinghouse until a need has been established based on a market survey of potential users. REFERENCES Clinton, W.J., and A. Gore, Jr. 1993. The Climate Change Action Plan. Washington, D.C.: The White House. 15 Asterisks (*) identify the most important recommendations.
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--> COGARN. 1987. Coal Gasification: Direct Applications and Synthesis of Chemicals and Fuels. U.S. Department of Energy Coal Gasification Research Needs Working Group, DOE/ER-0326. Washington, D.C.: DOE. DOE. 1991. Report to Congress: Coal Refineries: A Definition and Example Concepts. U.S. Department of Energy, DOE/FE-0240P. Washington, D.C.: National Academy Press. DOE. 1993a. Clean Coal Technologies: Research, Development, and Demonstration Program Plan. U.S. Department of Energy, DOE/FE-0284. Washington, D.C.: DOE. DOE. 1993b. Direct Coal Liquefaction Baseline Design and System Analysis: Final Report on Baseline and Improved Baseline, Executive Summary. Prepared for U.S. Department of Energy, Pittsburgh Energy Technology Center, under contract no. DEAC22 90PC89857. Pittsburgh, Pennsylvania: DOE. DOE. 1994a. Strategic Plan: Fueling a Competitive Economy. U.S. Department of Energy, DOE/S0108. Washington, D.C.: DOE. DOE. 1994b. Fossil Energy Advanced Research: Strategic Plan. Review draft, July 15. Washington, D.C.: DOE. DOE. 1994c. Comprehensive Report to Congress: Clean Coal Technology Program, Completing the Mission. Washington, D.C.: U.S. Department of Energy. EIA. 1994. Annual Energy Outlook 1994. Energy Information Administration, U.S. Department of Energy, DOE/EIA-0383(94). Washington, D.C.: DOE. EPRI. 1993. TAGTM Technical Assessment Guide. EPRI TR-102275-VIR7. Vol. 1, Rev. 7. Palo Alto, California: EPRI. Frey, H.C., E.S. Rubin, and U.M. Diwekar. 1994. Modeling uncertainties in advanced technologies: Application to a coal gasification system with hot gas cleanup. Energy 19(4): 449-463. Gray, D. 1994. Coal Refineries: An Update. Prepared for Sandia National Laboratories by the Mitre Corporation under contract no. AF-7166. McLean, Virginia: The Mitre Corporation. Maude, C. 1993. Advanced power generation—A Comparative Study of Design Options for Coal. London: International Energy Agency Coal Research. Merrow, E., K.E. Phillips, and C.W. Myers. 1981. Understanding Cost Growth and Performance Shortfalls in Pioneer Process Plants. Prepared for the U.S. Department of Energy by the Rand Corporation, R-2569-DOE. Santa Monica, California: Rand Corporation. NCC. 1994. Clean Coal Technology for Sustainable Development. Washington, D.C.: National Coal Council. NRC. 1992. The National Energy Modeling System. Energy Engineering Board, National Research Council. Washington, D.C.: National Academy Press. Tam, S.S., D.C. Pollock, and J.M. Fox. 1993. The combination of once-through Fischer-Tropsch with baseload IGCC technology. P. 306 in Alternate Energy '93 held April 28-30, 1993 in Colorado Springs, Colorado. Arlington, Virginia: Council on Alternate Fuels.
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