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Clean Coal Technology Demonstration Program FY1990 pub 1989
Clean Coal Technology Demonstration Program Fiscal Year 1990 Program Plan Clean Coal Technology Demonstration Program Fiscal Year 1990 Program Plan TABLE OF CONTENTS Page List of Figures... eee ee ee eee eee ii Teist of- Tables. —5 55 5 ee ose we tee oe eee re ot tes we on et ose eee iii 1.0:-The- Role of the-Program = 7. soi ae os one oe eee eo ertce tee oe 1-1 2.0 Potential Markets for Clean Coal Technologies .............0 000200 ee 2-1 3.0 Description and Commercialization of Clean Coal Technologies ............ 3-1 4.0 Goals and Strategy of the Clean Coal Technology Demonstration Prey enna alec leh a ls a orslaaece te al ott cl pctectg abc lated ete aetealtclertstne bolaaclertsl tletaaeetettt tee 4-1 5.0 Clean Coal Technology Demonstration Program Objectives ............... 5-1 6.0 Program Management ........... cee ee ee ee eee eee eee eee 6-1 7.0 Program Funding History and Budget ........... cee eee eee eee eee 6-1 APPENDIX A Clean Coal Technology-I Project Descriptions ................ A-1 APPENDIX B_ Clean Coal Technology-II Project Descriptions ..............- B-1 APPENDIX C_ State-of-the-Art Clean Coal Technology Candidates ............ C-1 APPENDIX D Federal Environmental Regulatory Requirements .............. D-1 Figure 4-1 Figure 4-2 Figure 4-3 Figure 4-4 Figure 5-1 Figure 6-1 Figure 6-2 Figure 6-3 LIST OF FIGURES Page Clean Coal Technology Demonstration Program Strategy .......... 4-3 Clean Coal Technology -Io ww... ee ee eee 48 The Clean Coal Technology-I Schedule Summary ............... 4-9 Clean Coal Technology-II .. 1... . ee ee ee eee ene 414 Clean Coal Technology Demonstration Program - Major Milestones 2... 0... ce eee eee ee ee eens 5-2 Clean Coal Program Organization... ........ cece eee ee eee 6-2 Morgantown Energy Technology Center ...............200005 6-4 Pittsburgh Energy Technology Center ................2 eee ee 6-5 Table 2-1 Table 3-1 Table 3-2 Table 3-3 Table 4-1 Table 4-2 Table 6-1 Table 7-1 LIST OF TABLES Page Summary of Market Applications .......... 0... 0s ee eee eee 2-2 Retrofit Technologies 2.2... . 2... eee ee eee ee eee 3-3 Repowering Technologies ... 1.0... . cee ee eee eee eens 3-5 Conversion Technologies ... 2... .. cee eee ee eee ee eee 3-6 CCT-I Projects 22... . ee ee ee eee ene 4-6 CCT-II Projects 2.1... kc ee ee ee ee eee eens 412 Clean Coal Technology State and Institutional Participation 2... . ee ee eee eee eee 611 Clean Coal Technology Demonstration Program Funding Profile ....... 0... .. cc eee eee ee eee eee 7-3 iii 1.0 THE ROLE OF THE PROGRAM The Clean Coal Technology Demonstration Program is a technology demonstration program jointly funded by government and industry. The Program will take the best and most promising of the advanced coal-based processing and emission control technologies and, over the next decade, advance their technical, environmental and economic performance to the point where the private sector will introduce the demonstrated technologies into the commercial marketplace. These demonstrations will be at a scale large enough to generate all data (from design, construction and operation) necessary for the private sector to judge their commercial potential and to make informed, confident decisions on commercial readiness. The objectives of the Program respond directly to the strategic importance of coal both in the United States economy and in the international marketplace by implementing the activities required to resolve the conflict between the expanded role coal must play as an energy option for the United States and the growing concerns about the environmental impacts of such use. 1.1 THE DEMAND FOR INCREASED USE OF COAL Solutions to a number of key energy issues are directly dependent upon the degree to which coal can be considered an available energy option. These issues include: ¢ long range requirements for increased power demand; ¢ need for energy security; and ¢ increased competitiveness in the international marketplace. 1.1.1 Requirements for Increased Power Production The convergence of two trends, aging power plants and increasing power demand, is occurring at the same time environmental requirements for new power plants are becoming increasingly stringent. Since the passage of the Clean Air Act, Prevention of Significant Deterioration (PSD) regulations have significantly increased the permitting time for major new sources of emissions. In addition, the Clean Air Act amendments of 1977 introduced nonattainment area requirements for new sources requiring, in many cases, emission levels for individual plants that are more stringent than national emission standards. Today’s technology will have difficulty in satisfying the rapidly changing requirements being placed on power plants. New power options must be capable of meeting stringent siting and environmental demands without sacrificing productivity. The importance of new, more economical environmental control technologies is underscored by the fact that approximately 40 percent of the capital investment and 30 percent of the total cost of power for new, conventional, coal-fired power plants are related to environmental controls. The power plant of the future must not only be clean and economical but also be capable of being rapidly constructed, preferably in modular fashion, with a high degree of performance 1-1 efficiency over a range of unit sizes. Future environmental control options must be less sensitive to fuel type and retain acceptable economics over a wide range of boiler sizes and models. Present-day commercial technology cannot meet these objectives in many situations. In fact, conventional commercial technology--both for power production and pollution control--is nearing the end of its development potential. Therefore, the next 5 to 10 years will be critical to the development of new energy options that are more economic, efficient and environmentally responsive and that will meet America’s energy, economic, and environmental goals. 1.1.2 Coal and Energy Security Coal’s abundance makes it one of the nation’s most important strategic resources in building a more secure energy future. (Coal comprises approximately 80 percent of the currently known domestic fossil fuel resources.) Coal can be one of the country’s most useful energy sources well into the twenty-first century and beyond. With current prices and technology, United States recoverable reserves of coal could supply the nation’s coal consumption at current rates for nearly 300 years.- Although the United States is endowed with vast quantities of coal, its characteristics tend to inhibit its greater use as a fuel. While lower coal prices would promote some increase in consumption, more substantial demand increases are hindered, currently, by various technical, regulatory, and environmental obstacles. If coal is to reach its full potential, economically competitive, advanced coal-using and conversion systems must be developed. These systems must be sensitive to diverse energy markets and site-specific factors as well as stringent environmental requirements. An expanded slate of advanced clean coal technologies would provide substantially improved options that are preferable to today’s choices. The development and deployment of clean coal technologies would reduce the technical obstacles, while an initiative to review and modify regulatory barriers would offer the potential to create incentives for investment in new, upgraded, environmentally responsive, clean coal-using and conversion facilities. 1.1.3. Increased Competitiveness of Coal in the International Marketplace New technology is a major factor in making the coal export package attractive. Such technologies may provide the single most important advantage that the United States could have in the global race for new markets. The ability to show a prospective overseas customer an actual operating facility running on United States coal, rather than just a drawing-board concept or an engineering prototype, is expected to be a very persuasive inducement. It easily could be the advantage that will sway Overseas consumers to buy an American package of coal and the proven clean coal technologies to burn it cleanly and effectively. The opportunity is consistent with and recognizes the increasing demand for safe, effective technology that does not impose further burdens on environmental quality. The development of advanced clean coal technologies also 1-2 will satisfy the demand for lower cost, more highly efficient energy concepts that will not reverse the recent gains in economic growth by imposing new costs on consumers. The marketing advantage of advanced clean coal technologies in supplying these equipment demands is clear when it is recognized that most of the technology on the market is 1940 vintage. Most of it could not stand up against the efficiency or cleanliness of modern fluidized-bed boilers or other advanced combustion or conversion concepts. Hardware and power generating concepts--from combustors to gas cleanup to advanced sensors, instrumentation, and diagnostics to repowering technologies, such as pressurized fluidized-beds and gasification combined cycles--can be an effective marketing tool when included with the coal itself. The linkage can be a most effective marketing edge and can provide essential options to foreign utilities to address problems similar to those expected by the United States power industry. Unless resolved, these problems will adversely impact the industry’s ability to meet increased demands in an environmentally acceptable, manner. The future of coal as an acceptable, and perhaps desired energy option, lies in the development and subsequent use of these advanced clean coal technologies. 1.2 IMPEDIMENTS TO THE INCREASED USE OF COAL While substantial deposits of coal exist as a resource suitable for and capable of resolving the critical near term and long range energy issues, a number of obstacles exist to not only limit its general availability but to act also as a barrier to its increased use. These impediments include: * concerns about environmental issues; ¢ availability of the technology; ¢ performance of the technology; and ¢ regulatory barriers. 1.2.1 Environmental Issues 12.1.1 Coal use and acid rain emissions The combustion of coal results in the generation of a number of gaseous compounds or emissions. Among these molecules species are sulfur dioxide and oxides of nitrogen. These emissions are believed to contribute to the formation and deposition of "acid rain". In March 1985, President Reagan and Canadian Prime Minister Mulroney appointed Special Envoys, Drew Lewis of the United States and William Davis of Canada, to assess the international environmental problems associated with transboundary air pollution, and to recommend actions that would help to solve them. The Special Envoys were assigned four specific tasks: 1-3 1. pursue consultation on laws and regulations related to pollutants thought to be linked to acid rain; 2. enhance cooperation in research efforts, including research on clean fuel technology and smelter controls; 3. | pursue means to increase exchange of relevant scientific information; and 4. identify efforts to improve the United States and Canadian environments. The Joint Report of the Special Envoys on Acid Rain resulted from these efforts. In this report, the Special Envoys concluded that acid rain is a serious environmental problem in both the United States and Canada, that acidic emissions transported through the atmosphere undoubtedly are contributing to the acidification of sensitive areas in both countries (a transboundary problem), and that potential for long-term socioeconomic costs is high. Concerning solutions to the acid rain problem, the Special Envoys concluded that, at present, there are only a limited number of potential avenues for achieving major reductions in acidic air emissions, and they all carry high socioeconomic costs. In particular, the Joint Envoys’ Report noted that none of the conventional methods now available for controlling emissions provide a simple solution to the problem. The report contained a number of recommendations to mitigate the problems, including the recommendation that the United States government implement a five-year $5 billion industry/governmental cost-shared control technology commercial demonstration program in which the federal government would provide up to one-half of the funding for the projects. Industrial sponsors were to contribute at least fifty percent of the funding. Because this technology demonstration program would be part of a long-term response to the transboundary acid rain problem, the Special Envoys recommended that prospective projects should be evaluated according to several specific criteria: ¢ The federal government should co-fund projects that have the potential for the largest emission reductions, measured as a percentage of sulfur or nitrogen oxides removed. ¢ Among projects with similar potential, United States government funding should go to those that reduce emissions at the cheapest cost per ton. ¢ More consideration should be given to projects that demonstrate retrofit technologies applicable to the largest number of existing sources, especially existing sources that, because of their size and location, contribute to transboundary air pollution. ¢ Special consideration should be given to technologies that can be applied to facilities currently dependent on the use of high-sulfur coal. On March 18, 1987, President Reagan announced several steps to ensure a continued close working relationship between the U.S. and Canada in determining and addressing the effects 1-4 of acid rain. The centerpiece of the President’s initiative was a pledge to seek $2.5 billion over a five-year period to fund innovative clean coal technology demonstrations. These demonstrations would be directed as closely as possible to the Special Envoys’ criteria. On February 9, 1989, President Bush reinforced the commitment to honor the recommendations of the Special Envoys and to seek the remainder of the $2.5 billion required to complete the Clean Coal Technology Demonstration Program on the original schedule. Funding would be used to structure multiple rounds of competition. The competitive procurements would be sequenced in such a way as to encourage new, potentially improved clean coal concepts, to continue their development and to consider them as candidate technologies once they reached sufficient maturity. President Bush also stated as part of his February 9th budget revision that the administration will propose new measures to reduce acid rain emissions. The legislative proposals, expected in June, will call for substantial reductions in emissions from the 1980 levels on a time schedule. The process for achieving these reductions will include expanded market-oriented choices to complement existing "command-and-control" regulatory authorities. | The administration’s approach anticipates that successfully demonstrated clean coal technologies will be major contributors to these reductions due to added commercialization incentives as well as acceleration of full-scale demonstration under the Clean Coal Technology Demonstration Program. 12.12 Coal use and global warming One of the critical environmental issues gaining national attention is the possibility of changes in global climate as a consequence of changes in atmospheric concentrations of "greenhouse" gases -- most notably carbon dioxide (CO,), methane (CH,), nitrous oxides (N,O) and chlorofluorocarbons (CFCs). The atmospheric concentration of CO, increased 9.5 percent between 1960 and 1986. It is generally agreed that combustion of fossil fuels is the primary contributor, although global deforestation has been a contributing factor. In 1986, the United States was responsible for 22 percent of the global CO, emissions from fossil fuel burning. Of this, electric power generation contributes 35 percent, transportation 30 percent, industrial sources 24 percent and the remaining 11 percent is contributed by the residential and commercial sectors. It is estimated that approximately 37 percent of the CO, emitted in the United States is attributable to the combustion of coal and thus accounts for 8 percent of global CO, emissions. Another "greenhouse" gas produced by the combustion of fossil fuels is N,O. Nitrous Oxide is produced in combustors as a function of both combustion conditions and fuel nitrogen content and recent data suggests that the N,O production rate is directly correlated with NO, production rates. Clean coal technologies can impact the emissions of "greenhouse" gases in two fundamental ways. With respect to CO,, many of the clean coal technologies improve the efficiency of the conversion of coal to useful energy. Technologies, such as pressurized fluidized bed, integrated gasifier combined cycle and fuel cells, will consume less coal per unit of useful energy produced and thus lower the amount of CO, emitted per unit of useful energy produced. Further, these repowering technologies in addition to low NO, burners, selective 1-5 catalytic reduction and other NO, reduction technologies will reduce NO, emissions which should result in N,O reductions. Gas reburning reduces NO, emissions up to 60 percent and can reduce CO, emissions from 5 percent-10 percent since combustion of natural gas produces less CO, than coal combustion. Should global warming be substantiated and reduction in emissions of "green-house" gases become a policy objective, the worldwide commercial deployment of clean coal technologies would take on added significance. 1.2.2 The Development of Technology Since the early 1970s, the Department of Energy (DOE) and its predecessor organizations have pursued a broadly based coal research and development (R&D) Program directed toward increasing the nation’s reliance on its most abundant fossil energy resource while improving environmental quality. This R&D program contains long-term, high-risk activities that support the development of innovative concepts for a wide variety of coal technologies through the proof-of-concept stage. However, the availability of a technology at the proof-of-concept stage is not sufficient to ensure its continued development and subsequent commercialization. Before any technology can be seriously considered for commercialization, it must be demonstrated. The risk associated with technology demonstration is, in general, too high for the private sector to assume in the absence of strong economic incentives or legal limitations. The implementation of a technology demonstration program has been endorsed as a way to accelerate the development of technology to meet near term energy goals, reduce risk to an acceptable level and to provide the incentives required for continued activity in innovative research and development directed at providing solutions to long range energy supply problems. Commercial availability dates of a number of clean coal technologies have been estimated by two knowledgeable external organizations--the Electric Power Research Institute and the Clean Coal Coalition. These estimates assume no delays in implementation of the Clean Coal Technology Demonstration Program and that the various technologies will have their commercial potential demonstrated across an envelop of applications and will be ready to compete on economic merits in the marketplace. The range of potential widespread commercial use predicted assumes that the industry will not be precluded from using the technology once it has been successfully demonstrated. Further, the time given between availability for commercial orders and actual commercial use reflects the time required for decision-making, engineering and construction. For a simple technology, this could be two to three years, and five to seven years for complex technologies. The time frames resulting from these analyses are consistant with the schedule of the Clean Coal Technology Demonstration Program. 1.2.3. Improvements in Technology Performance A key element in enabling coal to realize its potential in the nation’s energy future is to improve the technical performance of coal utilization and conversion technologies. Technical performance is measured in terms of efficiency, reliability, flexibility and emissions reductions. 1-6 Today’s technologies will have difficulty in responding to the changing requirements of the energy markets which are likely to exist in the next century. Progress in commercial coal technology, with the exception of industrial scale atmospheric fluidized bed combustion and flue gas desulfurization scrubber technology, has essentially stagnated in the past 20 years. While new coal technologies emerging from research and development show improved technical performance, they have not reached the energy markets. The Clean Coal Technology Demonstration Program presents the opportunity to demonstrate improved technical performance which can lead to significant reductions in the cost of using coal. Some of the attributes of clean coal technologies which will lead to an improvement in technical performance are: ¢ integration of emission controls into the coal utilization process thus increasing efficiency and reducing the complexity of the entire system and the quantity of required equipment, ¢ ability to use a wide variety and quality of coals thus relieving design constraints on siting future energy facilities; * reduced sensitivity to scale effects thus allowing modular construction and deployment of capacity in a timeframe and magnitude which will more closely match energy demand; and * production of waste by-products which are more easily managed and may be potentially marketable. The fundamental technical improvements demonstrated under the Program will allow an effective response to the changing energy market and a resolution of the conflict between the expanded use of coal and the environmental concerns of such use at the lowest possible cost. 1.2.4 Regulatory Barriers to Increased Coal Use Recognizing the possible role that regulations play in the decision-making process of the energy producer and user, the President formed a task force chaired by the Vice President to examine regulatory incentives and disincentives to the development and commercialization of new coal utilization technologies and to determine if changes were needed. On January 23, 1988 the President accepted the following recommendations of the President’s Task Force on Regulatory Relief: ¢ Preferential treatment, under the Innovative Control Technologies Program, for projects in states that, for rate-making purposes, treat innovative technologies the same as pollution control projects. This treatment would recognize the additional risk inherent in demonstration of innovative technologies. 1-7 ¢ A Federal Energy Regulatory Commission (FERC) five-year demonstration program allowing rate incentives for innovative technologies. This would also recognize the risk inherent in demonstrating innovative technologies. FERC already provides this type of incentive in certain circumstances. ¢ An Environmental Protection Agency program (1) encouraging states to consider achieving greater ozone reduction through inter-pollutant trading and other measures that substitute less expensive NO, emissions reductions for more expensive volatile organic compound emissions reductions; (2) encouraging the use of "bubbles" between recently built emissions sources; (3) expand commercial demonstration permits for innovative control technologies; and (4) encourage complementary use of emissions "bubbles" and waivers for innovative technology applications. Further, the Innovative Control Technology Advisory Panel (ICTAP), established by the President to advise the Secretary of Energy on funding and selection of innovative control technology projects, addressed the problems impeding the accelerated commercialization of clean coal technologies and issued a report to the Secretary of Energy concerning commercialization incentives in January 1989. The report included suggestions to address the problems encountered by clean coal technologies, including economic incentives (tax incentives, loans and grants), regulatory incentives (regulatory reforms and accelerated administration) and environmental incentives (environmental policy clarifications and waivers). The recommendations have, as their objective, the removal of impediments to, or in some cases, provide incentives for, clean coal technologies prior to full commercial availability. 1.3 A PROGRAM TO CREATE ENERGY SUPPLY OPTIONS FOR THE INCREASED USE OF COAL Recognizing the importance of resolving the conflicts between these energy and environmental issues, the Clean Coal Technology Demonstration Program has been concerned with objectives that when achieved: will permit the economic and environmentally acceptable direct utilization of coal, or produce a convenient, economical fuel form for use in electric utilities and industrial applications and to a lesser extent in the residential, commercial, and transportation sectors; and will reduce sulfur dioxide (SO,), nitrogen oxide (NO,), carbon dioxide (CO,), and particulate emissions to levels that are required, or may be required, for compliance with the Clean Air Act, as amended. When completed, this multi-phase Clean Coal Technology Demonstration Program will have developed and commercialized a new suite of advanced coal technologies including: * more effective precombustion coal cleaning processes; * new combustion techniques that remove sulfur and nitrogen pollutants during combustion; ¢ improved scrubber systems capable of removing sulfur and nitrogen pollutants without producing the wet sludges of today’s technology; 1-8 * improved cost-effective options to retrofit a diverse inventory of coal-fired power plants; ¢ advanced energy concepts that produce clean-burning fuels, such as coal-based liquid products or combustible gases; ¢ highly efficient, more environmentally benign coal-based combined-cycle power plants that can be fabricated easily and quickly in a wide range of modular sizes; and ¢ more efficient and environmentally acceptable coal-based industrial processes which will lead to increased competitiveness of the nation’s industrial sector. 14 THE RELATIONSHIP OF THE CLEAN COAL TECHNOLOGY DEMONSTRATION PROGRAM TO FEDERAL ENERGY POLICY The National Energy Policy Plan-V (NEPP-V) established the goal that the nation should have an adequate supply of energy, maintained at reasonable cost and consistent with environment, health and safety objectives. This goal presupposes three broad objectives: energy stability, energy security, and energy strength. Energy stability describes a situation in which problems of energy availability and price do not destabilize the U.S. economy, and economic growth is promoted. Energy security means that adequate supplies of energy are physically available to United States consumers from both domestic and foreign sources and that this nation is less vulnerable to disruptions in energy supply. Energy security leads to energy strength whereby it is possible to effectively utilize the vast energy resource base of the United States. Implicit in achieving these goals and objectives are the following strategies: ¢ minimize federal control and involvement in energy markets while maintaining public health and safety and environmental quality; and * promote a balanced and diversified energy resource system. The Clean Coal Technology Demonstration Program is consistent with and supports NEPP-V goals and strategy. Coal is the most abundant fossil energy resource in the United States, with recoverable reserves estimated at 935 billion barrels crude oil equivalent (COE). However, petroleum and natural gas, whose proven reserves are estimated to be 28 billion barrels and 35 billion barrels COE, respectively, are the most utilized fossil fuels in the United States energy consuming marketplace despite their significantly higher cost relative to coal. Coal use is demand driven; the capacity exists to increase coal supplies to meet significant increases in demand. However, to make coal utilization more attractive, DOE and the private sector have been conducting research, through proof-of-concept, on a wide variety of coal technologies aimed at improving the economics of using coal, improving environmental performance associated with its use and converting coal into forms that would allow it to be used as a lower cost substitute for oil and natural gas. The Clean Coal Technology 1-9 Demonstration Program will demonstrate the commercial feasibility of a new generation of coal-based technologies. When successfully demonstrated and commercially deployed, this suite of new technologies will make major contributions to NEPP-V goals of energy stability, security and strength since coal, while widely utilized, will meet public health and safety and environmental quality objectives. 1-10 2.0 POTENTIAL MARKETS FOR CLEAN COAL TECHNOLOGIES A significant potential exists for using clean coal technologies in the United States marketplace. This potential is being created by a number of factors that include: ¢ The need to limit and reduce the ever increasing quantity of foreign oil being imported to accommodate the United States demand for energy; ¢ The projected increase in electricity generating capacity that will be required over the next 25 years; ¢ The expected requirement for technologies that permit the use of coal in a manner consistent, not only with existing, but also with tightened environmental emissions standards; and ¢ The increasing level of international competition in the market for coal-based technologies that can accomplish a number of objectives simultaneously (i.e., increased efficiency, greater flexibility, minimized environmental impact, etc.). Because the clean coal technologies are expected to be more advanced, more efficient, reliable and economic, and more environmentally responsive than the state of the art technologies being used in all associated energy consuming sectors, it is anticipated that they will realize this potential. The market applicability of clean coal technologies is shown in Table 2.1. Under current projections using conventional technology, coal use is expected to double in the United States between 1986 and 2010. The availability of clean coal technologies could result in even greater coal use in the United States during this period. One reason for this is that advanced clean coal technologies offer the opportunity for coal to penetrate new markets. For example, clean coal technologies can contribute to relieving the pressures caused by high oil imports through the substitution of coal-derived liquids and other new fuel forms. Further, clean coal technologies can contribute to satisfying natural gas demand, and synthesis gas produced from coal could make a major contribution in chemical production. To evaluate the market potential for clean coal technologies, a review of the projected energy supply and demand and the general economic forecast is useful. Analyses suggest that the total primary United States energy consumption is projected to increase from 77.0 quadrillion Btu’s (quads) in 1986 to 108.2 quads in the year 2010 (a rate of 1.4 percent per year). The Gross National Product (GNP) is projected to grow at 2.7 percent a year. The relative difference between growth in energy consumption and GNP growth reflects improved energy efficiency in the economy and continued reductions in energy intensity. Coal consumption is projected to increase steadily from 17.3 quads in 1986 to 36.0 quads in 2010 at an average annual rate of 3.1 percent. By 2010 coal will comprise over one-third of the United States energy consumption’. ‘Quantitative data were drawn from Long Range Energy Projections to the year 2010. Office of Policy Planning and Analysis. DOE/PE-0082. 2-1 7% Table 2.1 Summary of Market Applications. Technology HS MS LS Coal Sulfur Content Market Boiler Size Util. Ind. S Repowering CAFB PFBC Fuel Cell IGCC Adv. Slag. Comb. LIMB Low NO, Burner Sorb. Injec. Selective Cat. Red. Direct Lique. Indirect Lique. Coal-Oil Coproc. Adv. Phy. - Coal Cleaning a a ~ «mM OM * x KKK MM MM MK x eK OK * x KM KK OM x mM * i i a a x «eK OM Xx * ~~ KK mK mK OK x «mK MK * xm mm KM OM x «x mK OM xem KKK KKK KM OLE x «eK ~~ eK mK mm KM OM OM OO i a xX x «mK OM Application Greenfield * ~*~ mM mM MK * * ~ me mK Retrofit x em KM mK OM OM x Km mK OM 2.1 ELECTRIC UTILITY SECTOR The electric utility sector will account for most of the projected growth in coal demand. Electric utility consumption of coal is forecast to grow from 14.5 quads in 1986 to 31.4 quads in 2010*. Coal is expected to comprise over 60 percent of the energy consumed in this sector. The electric utility industry stands at the threshold of a fundamental change in the power generation technological base, just as the Clean Coal Technology Demonstration Program is getting underway. By the mid-1990s, many utilities will be increasingly confronted by the dual problem of an aging boiler inventory and the potential long-term need for increasing their power generating capacity. More than half of all coal-fired boilers will be 30 years old or older by the mid-1990s. Utility decision-makers will have to make some fundamental choices about many of these units—to retire, refurbish, repower, or replace them. In this same time frame, demand for electricity will be growing, and reserve margins in generating capacity will be declining. Utility decision-makers have been reluctant in recent years to invest in large, conventional baseload plants—either coal- or nuclear-fueled. Moreover, uncertainty over anticipated growth in power demand, coupled with uncertainty regarding future environmental regulations, have stalled many construction projects. Thus, the uncertainty in the timing associated with the anticipated future demand for new facilities, either to meet new demand or as a replacement for older units, plus today’s slowdown in construction, has created an opportunity for new clean coal technologies in the 1990s and the early twenty-first century. Specifically: * over 180 gigawatts (GW = megawatts x 10°) of additional coal-fired capacity will be required between 1995 and 2010 to satisfy increased demand; * approximately 59 GW of 1986 generating capacity will be replaced by 2010; and * up to 200 GW of generating capacity, which will become 30-35 years old between 1995 and 2010, will be available to be repowered with clean coal technologies. It is anticipated that the utility sector will be the largest United States market for clean coal technologies, assuming that market conditions encourage increased use of coal as other fuels either become less plentiful or more expensive. The utility market includes: ¢ new coal electricity generating capacity; * repowering of existing oil and gas capacity with coal; and ¢ replacement or repowering of coal-fired generating capacity. "Ibid. 2-3 The last decade has brought substantial changes in traditional electric power generation which must be recognized in the market for clean coal technologies. These changes—independent power production, Qualifying Facilities (QFs), and cogeneration all supported by regulatory provisions—can have a pronounced effect on the market for clean coal technologies. Independent Power Producers (IPPs) are wholesale producers of electricity that are not affiliated with any utility in the area in which IPPs are selling power and that do not have significant market power. Independent Power Facilities are not regulated on a cost-of-service basis. QFs, as defined under the Public Utility Regulatory Policies Act of 1978 (PURPA), are cogenerators and small power producers who sell power to utilities at avoided cost rates. Among the Notices of Proposed Rulemaking (NOPR) which the Federal Energy Regulatory Commission (FERC) proposed in March 1988 was one involving IPPs and another involving bidding programs. The former regulation is to streamline FERC regulation of IPPs and the latter is to allow state regulatory commissions and others to establish bidding procedures for rates in purchasing power from QFs under PURPA. These proposed rules have the potential to increase the availability, diversity, and competitiveness of alternative sources of power purchased by utilities. If these proposed rules are implemented, they could provide a market for new generating technologies. Coal-fired technologies have not fared well against natural gas-fired technologies in cogeneration markets. The reasons for this are: (1) the need to find relatively large steam loads that are commensurate with economically efficient coal plant sizes; (2) the relatively low capital cost of natural gas-fired systems; and (3) the aggressive marketing strategy of the natural gas industry. Under the proposed rules, FERC anticipates that private power producers would not be constrained by the first reason. In the Draft Environmental Impact Statement’ on IPPs and QFs, FERC estimates that without the implementation of these NOPRs, QF capacity will grow modestly (15 GW added between 1990 and 2000 and an additional 8 GW between 2000 and 2005). Natural gas-fired systems will account for over 50 percent of total QF capacity in 1990, with coal accounting for 10 percent of this capacity in 1990. The emergence of IPPs, QFs, and cogeneration have caused the client base for the clean coal technologies to grow beyond the traditional utility industry thus opening new opportunities. Since these generating facilities are smaller and more dispersed, modular technologies, such as repowering technologies demonstrated under the Clean Coal Technology Demonstration Program, will be most advantageous. >The environmental consequences of independent power production are addressed in Draft Environmental Impact Satement: Regulations Governing Independent Power Producers (RM88- 4-000) and Regulations Governing Bidding Programs (RM88-5-000). Federal Energy Regulatory Commission, June 1988. 2-4 2.2 DIRECT COAL, PETROLEUM, AND NATURAL GAS USE IN NON-UTILITY SECTORS Coal accounts for less than 16 percent of the United States industrial fuel market today, with oil and natural gas each commanding over 40 percent. However, the direct use of coal in the industrial sector is expected to more than double by 2010 increasing from 1.5 quads in 1986 to 3.4 quads in 2010*. Thus, the potential market for coal in this sector is substantial and represents a significant opportunity for clean coal technologies. At present, over 1360 process steam-producing coal-fired boilers are in use by industry in the United States. Clean coal technologies, such as fluidized-bed combustion, appear to be attractive options for both existing and new industrial applications. Industrial coal feedstock use (mainly coking coal) is expected to decline at a rate of 1.8 percent/year, resulting in a decrease from 1.1 quads in 1986 to 0.7 quad in 2010°. Coal consumption for power generation in the industrial sector is restricted primarily to very large cogenerators or to particular circumstances where coal is readily available. Between 1986 and 2010, coal consumption for cogeneration is expected to grow from 0.1 quad to 0.5 quad. Direct coal use in the residential and commercial sectors is expected to remain at 0.1 quad throughout the period. Petroleum will remain the predominant fuel through 2010, contributing over 40 percent of total national energy consumption. The nation’s continued dependence on petroleum is of increasing concern from an energy stability, security, and strength standpoint as projections indicate that the nation, by 2010, will find itself more dependent on imports from less stable regions of the world. Although the Clean Coal Technology Demonstration Program largely addresses retrofitting and repowering existing coal-fired facilities, important spinoffs can contribute to relieving pressures caused by high oil imports through: 1. substitution of coal-derived liquids and alternative fuels for use in the petroleum consumption sectors. For example, non-energy use of petroleum in the industrial sector is expected to be 4.6 quads, or over 45 percent, of the petroleum consumed in this sector. This represents an important market target for coal-derived liquids as infrastructure impacts would be minimal. 2. providing clean coal technologies which will enable industry, and possibly larger residential and commercial sector users, to switch from oil to coal. These technologies include advanced combustion, alternative fuels, coal liquefaction, coal gasification, fluidized-bed combustion, fuel cells, heat engines, and advanced coal preparation. ‘Long Range Energy Projections to the Year 2010. ‘Thid. Natural gas consumption is projected to increase until 2000 and then remain constant. As in the case of petroleum, clean coal technologies can have significant spinoffs and can contribute to satisfying natural gas demand. For example, in the industrial sector, over 0.5 quad of natural gas is currently used as industrial feedstocks. Synthesis gas produced from coal could make a major contribution in this sector if coal gasification technologies are successfully demonstrated and subsequently deployed in the marketplace. Further, coal gasification technologies can produce synthetic natural gas, which directly displaces natural gas and utilizes the vast network of pipelines which exist in this country. 2.3 INTERNATIONAL MARKETS International markets also offer commercial opportunities for the clean coal technologies being developed and demonstrated in the United States. Energy consumption in the European countries of the Organization for Economic Cooperation and Development (OECD), Japan, and developing economies combined is projected to grow significantly faster than in the United States through the year 2000. Japan, however, has made enormous strides in reducing energy intensity per capita, and it is likely that energy consumption will remain relatively low despite economic expansion. To some degree, growth in the projected energy demand may depend upon the extent to which foreign consumer products penetrate the Japanese domestic markets. The developing economies are expected to increase energy consumption at a greater rate than other global economies. The International Energy Agency (IEA) projects that between 1990 and 2000 developing economies will increase their energy consumption to the extent that by 2000 developing economies will consume more energy as a group than will Western Europe. In developing economies, the commercial sector is expected to account for the increase. Capital constraints affecting power plant construction and other industrial enterprises may temper those numbers, but the trend is appropriately cast. In Western Europe, nations are establishing stringent environmental regulations. Pollution control technologies are of interest rather than just using lower sulfur coal as a pollution control strategy. This suggests some opportunity for United States clean coal technologies. IEA projects that OECD Western Europe as a region will require 265 GW of new electric capacity by the year 2000, of this, approximately 44 GW will be coal-fired capacity. This large projected growth in energy consumption worldwide offers a potentially sizable market for United States exports of coal, coal-based fuels and coal technologies. New technology is a major factor in making the coal export package attractive. The technologies emerging from the Clean Coal Technology Demonstration Program may provide the single most important advantage that the United States could have in the global race for new technologies and new energy supplies. 2-6 3.0 DESCRIPTION AND COMMERCIALIZATION OF CLEAN COAL TECHNOLOGIES 3.1 INTRODUCTION The term "clean coal technology," as used by DOE’s Office of Fossil Energy, refers to advanced coal-based systems that offer significant potential for improved environment and economic performance in power generation and industrial applications, as well as for other uses. For power generation, clean coal technologies can improve performance and thermal efficiency and thus dramatically improve the economics of operation. Clean coal technologies can be used to minimize the system’s environmental impact, and many can be added to the utility in modular fashion to permit the utility to match supply and demand requirements more closely. The technologies can be designed to use a variety of coals, and they can be used to repower existing coal-fired boilers, extend plant life, increase the plant’s power output, and, at the same time, greatly reduce emissions. The clean coal technologies used to address some of the current as well as projected problems in power generating systems include fluidized-bed combustion, integrated gasification combined-cycle systems, fuel cells, direct coal-fired turbines and diesels. For pollution control, clean coal technologies can be used to reduce the amounts of sulfur oxides (SO,), nitrogen oxides (NO,) and other pollutants discharged from coal burning systems. These technologies can be used for meeting New Source Performance Standards (NSPS) for new boilers more economically than conventional control equipment. Clean coal technologies also are potentially low-cost retrofit devices for meeting state or local environmental Tequirements for existing units. Clean coal technologies can include coal conversion processes that have the capability to produce liquid and gaseous fuels for all market sectors (utility, industrial, commercial, residential and transportation). These technologies include coal gasification, coal liquefaction, in-situ gasification and coal/oil coprocessing. These technologies have the potential to increase energy efficiencies over currently available technologies as well as increase the use of domestic coal reserves. Clean coal technologies offer the opportunity to produce usable energy at costs much lower than current state-of-the-art systems. From an environmental standpoint, clean coal technologies open the door to a future of sustained reductions in the acid rain precursors, SO, and NO,. Further, the high efficiency offered by some of the technologies will reduce the amount of coal burned and thereby reduce emissions of CO,. The majority of the clean coal technologies in this program are generally grouped into one of three categories: (1) retrofit technologies that can be used on existing plants to reduce emissions; (2) repowering technologies that replace a significant portion of the original plant and increase the power output of the facility; or (3) conversion technologies that have applicability in the utility, industrial, commercial, transportation and residential markets by utilizing coal conversion processes that produce liquid and gaseous fuels. It should be 3-1 recognized that many of the technologies in these categories can be applied to new plants as they will meet or exceed the requirements of New Source Performance Standards. A detailed description of clean coal technologies is contained in Appendix C. 3.2 RETROFIT TECHNOLOGIES As shown in Table 3-1, retrofit technologies include concepts such as advanced coal cleaning, limestone injection multistage burners (LIMB), slagging combustors, gas reburning, in-duct sorbent injection, coal-water mixtures and advanced flue gas cleanup. These technologies, used separately or in combinations, can control both SO, and NO,. Although, some may be less able to reduce sulfur emissions than conventional flue gas scrubbing, these retrofit technologies can reduce levels sufficiently to meet possible future environmental requirements for existing plants. Of increasing interest is the ability of many retrofit technologies to be operated as combined systems. Benefits of such operation can include greater reductions in SO, and NO, emissions as well as costs. For example, coal cleaning combined with duct injection and combustion modification can significantly reduce both pollutants. By combining coal cleaning and duct injection, the overall cost of reducing SO, emissions can be cut for many coals. The relative benefits of combined systems mainly depend on the sulfur content of the coal and the efficiency of sorbent utilization in the control system. For example, advanced flue gas desulfurization technology which is being developed to address reliability, operability and waste disposal issues can be used in combination with NO, reduction technologies. In another case, furnace sorbent injection has a comparatively low sorbent utilization rate, the economics of pollutant reduction are significantly improved when the coal is cleaned first to reduce its sulfur content. Further, using physically cleaned coal in LIMB technology to remove 85 percent to 90 percent of the SO, is more cost effective than burning run-of-mine coal in a plant equipped with a wet limestone flue gas desulfurization (FGD) system. Thus, either by themselves or in combination, the advanced technologies have the potential to meet the wide variety of site-specific needs of individual utilities. This includes meeting NSPS and other requirements such as those of State Implementation Plans. Most of the retrofit technologies are designed to control emissions only. When NSPS were enacted in 1977, Congress anticipated a routine replacement of old and less stringently regulated equipment with new boilers having pollution controls. However, because of regulatory uncertainties, a demand for electricity lower than expected, and the high capital costs of new power generating equipment, electric utility companies are opting to extend boiler life. As a result, the anticipated routine replacement of old, uncontrolled facilities with new and less polluting plants is being delayed. If new pollution control regulations now being considered are established and the further control of emissions from these older boilers is mandated, the utility industry will be forced to make immediate decisions on control equipment. Utilities would have to choose from 3-2 Pre-Combustion Cleaning Physical + Fine Grinding (micronization) + Advanced Froth Flotation * Heavy Media Cyclones + Micronization w/Limestone * Microbubble Flotation Physiochemical * Molten Caustic Leaching * Organic Solvent Microbial * Bioleaching Table 3-1 Retrofit Technologies Combustion Modification Combustor/Burner Types * Slagging Combustors + Rotary Cascading Bed Combustors « Entrained Combustors + Limestone Injection Multistage Burners * Gas Reburning Fuel Types * Coal-Water Slurries * Coal-Gas Co-Firing * Coal-Water-Gas Co-Firing 3-3 Post-Combustion In-Duct Injection * Sorbent Injection * Catalytic Reduction Post-Combustion Devices Vanadium Pentoxide Afterburners Ternary Boiler w/Pollutant Capture ¢ Furnace Injection w/Water Activation Reactor *Post-Combustion Oxidation w/Fluid Bed Lime Reactor ¢ Fluid Bed Absorption Advanced Scrubbers/FGD Devices ¢ Spray Dryers + Regenerable Scrubbers * Dual Alkali Scrubbers * Electron Beam Scrubbers * lon Exchange Membrane FGD * Magnesium Enhancements *NOx Specific Scrubbers « Electrode Precharger Enhancements to Precipitators ¢ High-Temperature Baghouses today’s control options—flue gas scrubbers, coal cleaning, and coal switching. Development of advanced control systems would be delayed. The long-range impact of this delay would be increased power costs and less than optimal efficiency in the removal of pollutants. Moreover, the maximum reduction in pollutants would be considerably less than could be achieved with the advanced control systems. 3.3. REPOWERING TECHNOLOGIES Repowering consists of modifying aging coal-fired electric power plants with a new generation of environmentally improved, highly efficient coal utilization technologies. As shown in Table 3-2, this group of clean coal technologies includes concepts such as fluidized-bed combustion, gasification combined cycles as well as advanced options such as gasification with fuel cells, direct coal-fired turbines and diesels. A repowered coal-fired plant would retain much of its existing solids handling equipment and virtually all of its steam cycle, electrical generating, and power conditioning hardware. Thus, repowering also can be considered part of a life extension program. From an environmental standpoint, repowering opens the door to a future of sustained deep reductions in nationwide emissions of SO,, one of the chief pollutants thought to contribute to acid rain. Repowering concepts are among the cleanest of coal burning options. Fluidized-bed combustors can eliminate 90 percent to 95 percent of the potential sulfur pollutants during the combustion process itself, eliminating the need for postcombustion sulfur controls. Combined-cycle coal gasification systems can remove more than 99 percent of sulfur emissions from coal-derived gases. Repowering of a power generation facility would improve its emissions control capability, boost energy production efficiency, and enhance the cost-effectiveness of operation. Further, these repowering technologies can be used in new plants that will be constructed to satisfy future growth in electric power demand. 3.4 CONVERSION TECHNOLOGIES Coal conversion technologies have the capability to produce liquid and gaseous fuels from coal for use in industrial, commercial, residential, and transportation sectors. Examples of coal conversion technologies are listed in Table 3-3. Surface and underground coal gasification can produce clean fuels and chemical products for use in industrial or utility applications. If air is used in the process, a low-Btu gas is produced with a heating value in the range of 125-150 Btu/scf. Gasifying coal with oxygen creates a medium-Btu gas with heating values of 270-320 Btu/scf. Medium-Btu gas can be upgraded to synthetic natural gas or it can be used to produce various chemicals, such as methanol and ammonia. Coal liquefaction processes fall into four categories: direct liquefaction, indirect liquefaction, coal/oil coprocessing and pyrolysis. Direct liquefaction involves conversion of coal into liquids by reacting a slurry of coal, a process-derived solvent and hydrogen. The liquid product can be refined to produce a full range of refinery products including gasoline and industrial and home heating oil. Indirect 3-4 Table 3-2 Repowering Technologies Fluidized Bed Combustion Gasification-based Advanced Options Atmospheric Gasifiers Gasification w/Fuel Cell * Circulating Bed + Fixed Bed * Bubbling Bed + Fluid Bed Magnetohydrodynamics ¢ Entrained Flow Pressurized * Rotary Kiln Direct Coal-Fired Turbines + Circulating Bed * Bubbling Bed Gas Cleanup Systems * Conventional "Cool" Gas Hybrid Designs Cleanup ¢ Bubbling-Circulating Bed + Zinc Ferrite Hot Gas * Coal Pyrolyzer/Fluid Bed Cleanup * Ceramic Filter Cleanup + In-situ Desulfurization Table 3-3 Conversion Technologies + Mild Gasification * Gasification with Once-Through Methanol Production ¢ Underground Coal Gasification * Indirect Liquefaction + Direct Liquefaction * Coal/Oil Coprocessing liquefaction are those processes in which conversion of coal to liquid products is accomplished by first gasifying coal into a mixture of carbon monoxide and hydrogen and then causing these gases to react in the presence of a catalyst to form liquid products. A wide range of fuel and chemical products can be produced for use in all energy sectors. In coal/oil coprocessing, coal is slurried in residual fuel oil and both coal and petroleum residuals are converted to high-quality fuels in subsequent processing steps. Pyrolysis involves heating coal in the absence of air or oxygen to obtain heavy oil, light liquids, gases, and char. Alternative fuels involve suspensions or slurries of coal or coal-derived solid in water or combustible liquids. The alternative fuels include coal-water, coal-oil and coal-methanol mixtures. 3.5 TECHNICAL READINESS VS. COMMERCIAL READINESS Successful demonstration of a technology does not ensure that the technology will enjoy wide-spread commercial deployment. DOE is working closely with industrial participants in developing plans for technology transfer and commercialization. Further, the President’s Task Force on Regulatory Relief and ICTAP are addressing issues associated with regulatory requirements and identifying incentives to better ensure rapid deployment of the technologies. In the electric utility industry, reliability of power generation technology is a paramount consideration. A concern raised by the utility industry regarding clean coal technologies is their long term reliability under utility operating conditions. Commercial potential for the electric utility industry may require complementary demonstrations of a clean coal technology in order to achieve confidence in a new technology and to reduce the risk and cost of commercial deployment. A number of factors combined over time will increase the confidence in a new technology and will lead to risk reduction. These include the following: ¢ learning by the industrial participants and the technology owners; ¢ technical improvements; and * economics associated with larger units. This increased confidence and risk reduction can be achieved within the framework of the Clean Coal Technology Demonstration Program by demonstrating performance under different conditions (e.g., location, coal type, system configuration) rather than replication. Data will be available to ensure that an adequate confidence level is established. This data, supplemented with aggressive marketing activities of industrial participants, should allow rational technical, economic and environmental decisions to be made by the private sector in a time frame consistent with the "window of opportunity" which will exist in the late 1990s. 4.0 GOALS AND STRATEGY OF THE CLEAN COAL TECHNOLOGY DEMONSTRATION PROGRAM 4.1 PROGRAM GOAL The goal of the Clean Coal Technology Demonstration Program is to make available to the U.S. energy marketplace a number of advanced, more efficient, reliable and environmentally Tesponsive coal utilization, conversion and environmental control technologies. These technologies will address, reduce and/or eliminate the economic and environmental impediments that limit the full consideration of coal as a future energy resource. This goal will be accomplished by stimulating the development and fostering the commercialization of these technologies through the joint government/industry support of demonstration projects. The amount of data required on each project for the private sector to make rational and confident decisions regarding commercial deployment will vary among the technologies and will be related to their unique characteristics and the application in which they are used. Such considerations as acceptable level of operational risk (e.g., the utility industry is known to be risk adverse), degree of reliability, operational maturity etc., will be resolved by the data generated. The overall schedule associated with achieving the program goal recognizes three time critical factors: « Almost 50% of the current inventory of electrical generating capacity in the United States will be over 30 years old by 1997. The need to replace or refurbish this capacity plus add new capacity to keep pace with the rising demand for electricity means that a major investment in electrical generation capacity will begin by the mid 1990s. Better technologies must be available for use on a commercial basis prior to the year 2000 to prevent the economic and environmental penalties associated with continued investments in currently available state-of-the-art commercial technologies. ¢ The concerns regarding acid rain and the debate over how best to solve this environmental problem are creating a polarization in the United States between those who favor solving it via regulation and those who seek achieving a solution with less severe economic consequences by using improved technology. Truly superior technology options must be forthcoming in the foreseeable future to prevent the selection and implementation of the regulatory, economic-adverse option. It is critical that the Clean Coal Technology Demonstration Program validate the availability of options that will not require the nation to choose between a healthier environment and higher energy costs. e Other promising advanced technologies offering a wide range of future coal utilization options but not now sufficiently mature to justify demonstration will become available in the early 1990s. Subsequent demonstration of these technologies will make it possible for coal and coal derived energy products to replace oil and gas in a wide range of applications. 4-1 4.2 PROGRAM STRATEGY The strategy being implemented to achieve the goal of the Clean Coal Technology Demonstration Program is to conduct a multi-phase effort consisting of five separate solicitations for projects (Figure 4-1), each with individual objectives that will, when integrated, make available the desired series of technology options on a schedule consistent with the demands of the energy market and responsive to the relevant environmental considerations. The data generated by the projects selected will become the technical, environmental, operational, performance and economic information base necessary to reduce the risk of commercial deployment by the private sector to an acceptable level. The federal government’s role is to capture, assess and transfer to a broad spectrum of the private sector and international community, sufficient technical, environmental, economic and operational information to allow potential commercial users to confidently screen the generic technologies for those which meet their operational requirements. It is the technology owners’ role to retain and use the information and experience gained during the project to promote the technology in the commercial marketplace. The detailed technical, economic, environmental, and operational data and experience gained during the project will be vital to firms deciding whether to invest and build retrofit or repower plants using clean coal technologies. This aspect of the industrial participants’ role in the Clean Coal Technology Demonstration Program is crucial to the ultimate goal of commercializing the successfully demonstrated technologies. The federal role further includes: developing a technical, engineering, and environmental knowledge base so that sound policy decisions on future clean coal technology initiatives and environmental issues can be made, and providing the public with requisite information on the control of potential pollutants which may contribute to acid rain so that a national consensus can be formed. Finally, the government has made provisions for adequate technology transfer mechanisms that will be in place to assure that the private sector has the necessary access to the clean coal technologies. While not having a direct role, the Clean Coal Technology Demonstration Program supports a secondary strategy which is to improve the regulatory and institutional climate for deployment of demonstrated clean coal technologies at a pace consistent with free market decisions. This secondary strategy involves providing information on the regulations affecting commercialization and, where appropriate, implementing the recommendations of the President’s Task Force on Regulatory Relief and the recommendations of the Innovative Control Technology Advisory Panel (ICTAP) which have emerged from its analysis of issues surrounding accelerated commercialization of clean coal technologies. Also, the secondary strategy involves working with other federal agencies, states, and international and private organizations to foster an understanding of the Clean Coal Technology Demonstration Program and its projects, and building a consensus on the benefits to be derived from the demonstration and subsequent deployment of clean coal technologies. The execution of the above strategy presupposes the following assumptions: 4-2 t+ FY 1986 Figure 4-1 CLEAN COAL TECHNOLOGY DEMONSTRATION PROGRAM STRATEGY FY 1987 FY 1988 CCT-1 : * Expanded use of _ coal : + Utilization of total — coal resource base + Technology Transfer — FY 1989 FY 1990 FY 1991 FY 1993 Demonstrated CCT-IV * Special Envoys on Acid Rain resource base CCT-Il recommendations + Utilization of total coal '* Advanced concept » Special Envoys | Technology i _on Acid Rain | recommendations | * Solid waste : | reduction | | * Technology | | Transfer : | 1 4 1 | Commercialized Clean Coal Technologies Information & Experience Clean Coal | | | Technologies | | CCT-Ill * Special Envoys on Acid Rain — + Utilization of total recommendations coal resource base * Global warming * Future Energy Needs + Solid Waste Reduction * Technology Transfer CCT-V sSpecial Envoys on Acid Rain recommendations * Complementary demonstrations * Technology transfer ¢ The Administration/Office of Management and Budget fully endorses the President’s initiative to fund the $2.5 billion Clean Coal Technology Demonstration Program. ¢ DOE carries out congressional direction set forth in P.L. 99-190 which provides $397.6 million to conduct cost-shared clean coal projects for the construction and operation of facilities that would demonstrate the feasibility of future commercial applications of such technology. ¢ DOE carries out congressional direction set forth in P.L. 100-202 which provides $575 million to conduct cost-shared Innovative Clean Coal Technology (ICCT) projects to demonstrate emerging clean coal technologies that are capable of retrofitting or repowering existing facilities. ¢ Appropriations of $1.775 billion--$575 million in FY 1990, $600 million in FY 1991 and $600 million in FY 1992--are obtained for the balance of the $2.5 billion recommended by the Special Envoys on Acid Rain and endorsed by the President. ¢ DOE carries out congressional direction set forth in P.L. 100-446 and issues a third solicitation in May 1989 and selects projects no later than December 27, 1989. ¢ Congress does not enact acid rain legislation that could preempt application of clean coal technologies in lieu of the more expensive, but available, flue gas cleanup systems by forcing action before clean coal technologies can be commercialized. 4.2.1 The Clean Coal Technology-I (CCT-1 On December 19, 1985, Congress passed Public Law 99-190, An Act Making Appropriations for the Department of the Interior and Related Agencies for the Fiscal Year Ending September 30, 1986, and for Other Purposes. Included in this act were provisions for funds to conduct cost-shared, clean coal technology projects for constructing and operating facilities demonstrating the feasibility of future commercial clean coal applications. By congressional directive, the first solicitation for federal cost-sharing was open to all market applications of clean coal technologies that apply to any segment of the United States coal resource base. The solicitation also encompassed both "new" and "retrofit" applications. By congressional directive, DOE issued a Program Opportunity Notice (PON) on February 17, 1986. With the receipt of 51 proposals by the April 18, 1986 deadline, DOE initiated a rigorous evaluation process that extended over three months. This evaluation process resulted in the selection on July 25, 1986 of nine initial projects for negotiation and the identification of an alternate list of 14 projects to be considered if negotiations could not be successfully completed with any of the initial candidates. Cooperative agreements were executed with seven of the industrial participants originally selected. Two industrial participants withdrew their proposals from further consideration. The funds made available as a result of these withdrawals allowed the selection of four additional projects from the list of alternate projects. Negotiations on two of these projects have been completed and the cooperative agreements have been executed. One of the alternative projects 4-4 withdrew from negotiation and three additional projects were selected from the alternative list. By mutual agreement, one cooperative agreement was terminated because of siting problems. DOE selected another project from the alternative list. The thirteen projects now in the program are listed in Table 4-1 and are described in Appendix A. The distribution of these projects within the U.S. is shown in Figure 4-2. The Schedule for the CCT-I project is shown in Figure 4-3. The goal of the CCT-I will be accomplished through the demonstration of 13 technologies by 1995. The CCT-I projects will demonstrate six technologies which can be retrofitted on existing plants, five technologies which can be used to repower existing plants or used in new plants and two technologies for conversion of coal to more usable energy forms. While most of the technologies can be applied to any segment of the nation’s coal resource base, the use of over fifteen different eastern and western coals will be specifically demonstrated. 4.2.2 Clean Coal Technology-II (CCT-I) While CCT-I is directed at demonstrating technologies that can, through increased efficiency and flexibility, increase the role of coal as an energy option, CCT-II is more focused and directed specifically on demonstrating technologies that can overcome the impediments to increased use of coal created by the issues of acid rain. The objectives are derived principally from the efforts and results of the Special Envoys Report. In March 1985, the President appointed Drew Lewis to be the United States Special Envoy on Acid Rain, and at the same time, Prime Minister Brian Mulroney appointed William Davis as the Canadian Special Envoy. The Special Envoys were charged with the responsibility to assess the international environmental problems associated with transboundary air pollution, and then recommend actions that would solve them. In January 1986, the Envoys presented their findings and recommendations. Beyond their recognition of the international nature of acid rain, the Envoys made three key recommendations: ¢ The initiation of a 5-year, $5-billion program in the United States for commercial demonstration of control technology projects recommended by industry and jointly funded by government and industry. ¢« A commitment to ongoing cooperative activities, including bilateral consultations and information exchange. ¢ A greater emphasis on carrying out research essential to resolving transboundary acid rain issues. Because the technology demonstration program was meant as part of a long-term response to the transboundary acid rain problems, the Envoys also recommended specific criteria for the evaluation of prospective projects. 4-5 Table 4-1 CCT- | Projects Project and Industrial Participant Project Project Location Tidd PFBC Demonstration Project (American Electric Power Service Corporation) LIMB Demonstration Project Extended Test of Limestone Injection Extension Multistage Burner Plus Sorbent Duct (The Babcock & Wilcox Company) Injection, 105 MWe Pressurized Fluidized-Bed Combustion Combined-Cycle Utility Retrofit, 70 MWe Brilliant, OH Lorain, OH Advanced Cyclone Combustor Demonstration Project (Coal Tech Corporation) Slagging Combustor and Sorbent Injection into Combustor, 1 Ton/hr. Williamsport, PA Gas Reburning/Sorbent Injection Gas Reburning and Sorbent Injection Demonstration Project Retrofit into Three Utility Boilers, (Energy and Environmental Research 117 MWe, 80 MWe, 40 MWe Corporation) Bartonville, Hennepin, and Springfield, IL Steeply Dipping Bed Underground Coal Gasification Integrated with Ammonia/ Urea Plant, 500-1,000 Tons of Coal/Day Underground Coal Gasification Rawlins, WY Demonstration Project (Energy International, Inc.) Coal-Oil Coprocessing Liquefaction (Process 800 TPD Coal, Plus Residual Oil to Yield 11,750 BPD Clean Distillate Liquid) Prototype Commercial Coal/Oil Warren, OH Coprocessing Plant (Ohio Ontario Clean Fuels, Inc.) Nucla CFB Demonstration Project (Colorado-Ute Electric Association, Inc.) Clean Energy IGCC Demonstration Project* (Foster Wheeler Power Systems, Inc.) Advanced Slagging Coal Combustor Utility Demonstration Project (TRW, Inc.) Cleaned Coal Combustion Tests Project* (Combustion Engineering Inc.) Hopkins Project (City of Tallahassee) Circulating Fluidized-Bed Combustion, Nucla, CO Utility Retrofit, 110 MWe Integrated Combined-Cycle Power System for Coproduction of Power and Steam Advanced Slagging Coal Combustor with NOx and SOx Control Small Scale and 200-MW boiler combustion tests of coals cleaned by advanced process sponsored by EPRI Circulating Fluidized-Bed Combustion Retrofit, 250 MWe Richmond, VA Stoney Point, NY Cleveland, OH Homer City, PA Tallahassee, FL Project and Industrial Participant Microbubble Flotation Project* (United Coal Company) Novel Coal Cleaning Process Project* (Western Energy Co.) Table 4-1 (cont'd.) CCT- | Projects Project Recovery of fine particles of low sulfur coal from mine waste disposal pond. Improve heating value and reduce sulfur content of western coal. * Projects currently in the fact-finding process. 4-7 Project Location Logan County, WV Colstrip, MT 8 Figure 4-2 Clean Coal ‘AM. Elec. Power. TRW Inc. . Wi E Co. Serv. Corp. i Technology I Brilliant, OH, in, Suoney Foie NY Coal Tech Corp. Williamsport, PA Selected en ° Homer City, PA Projects “™ and Sites aN City of Tallahassee Tallahassee, FL Energy & Environmental} ‘ Colorado-Ute Elec. Research Corp. United Coal Co. Foster Wheeler nergy International Inc Springfield, Hennepin, : Rawlings, WY Assoc. Nucla, CO Poe ville, IL Sharples, WV Richmond, VA 6+ PROJECT: te American Electric Power Service (Tidd PFBC Demonstration Plant) Phase | Phase II Phase Ill . Babcock & Wilcox Company (LIMB Demonstration Project) Phase | Phase II Phase III . Coal Tech Corporation (Advanced Combustor Demo.) Phase | Phase II Phase Ill . Energy & Environmental Research Corp. (Gas Reburning Project) Phase | Phase I! Phase Ill . Energy International, Inc. (Underground Coal Gasification) Phase | Phase II Phase Ill . Ohio Ontario Clean Fuels, Inc. (Coal-0il Coprocessing) Phase | Phase Il Phase III Figure 4-3 THE CLEAN COALTECHNOLOGY - I SCHEDULE SUMMARY LF | FY93 OI-+ Figure 4-3 (cont'd) THE CLEAN COALTECHNOLOGY - I SCHEDULE SUMMARY PROJECT: 7. Colorado-Ute Electric (CFB Combustion Demo.) Phase | - 9/83-7/85 Phase Il Phase Ill I'o Be Negotiated Io Be Negotiated I'o Be Negotiated I'o Be Negotiated 'o Be Negotiated FY93 8. TRW, Inc. (Slagging Combustor Demo.) Phase | Phase Il Phase Ill 9. Foster Wheeler* (IGCC Demo.) 10. Combustion Engineering* (Cleaned Coal Combustion) 11. United Coal Company* (Microbubble Flotation) 12. Westem Energy Company* (Advanced Coal Cleaning) 13. City of Tallahassee (Circulating Fluidized-Bed Combustion)* *Projects Currently in Negotiation: In March 1986, the President endorsed the Special Envoys recommendations. His endorsement set in motion the development of an expanded clean coal technology program that would build on the CCT-I effort, reflect ongoing state and privately funded initiatives and be fashioned as fully as practicable from the guidelines recommended by the Special Envoys. The guidelines are as follows: ¢ The federal government should cofund projects that have the potential for the largest emission reductions, measured as a percentage of SO, or NO, removed. ¢ Among projects with similar potential, government funding should go to those that reduce emissions at the least cost per ton of emissions. * More consideration should be given to projects that demonstrate retrofit technologies applicable to the largest number of existing sources, especially existing sources that, because of their size and location, contribute to transboundary air pollution. Primary program emphasis would be placed on the demonstration of technologies that would be needed for any future acid rain control program. These projects should also result in some near-term reductions in United States air emissions that affect Canadian ecosystems. ¢ Special consideration should be given to technologies applicable to facilities currently dependent on the use of high-sulfur coal. Using these criteria and other congressional guidance, a second solicitation was prepared and released on February 22, 1988 and on September 28, 1988 sixteen additional projects were selected for the Program. These projects are listed in Table 4-2 and described in Appendix B. The location of these projects within the U.S. are shown in Figure 4-4. The selected CCT-II cost-shared projects will demonstrate technologies which are more cost effective than existing technologies and are capable of achieving significant reductions in SO, and/or NO, emissions from existing coal burning facilities, particularly those that contribute to transboundary and interstate pollution. Of the sixteen projects selected, thirteen technologies can be retrofitted on existing coal burning plants and three can be used to repower existing facilities. Results of analyses have shown that the generic technologies, represented by the CCT-I and CCT-II projects, if applied to 100 percent of the market to which these technologies are applicable, could result in significant reductions in national SO, and NO, emissions by the year 2010. 4.2.3 Clean Coal Technology-III (CCT-IID) Language in P.L. 100-446, Making Appropriations for the Department of the Interior and Related Agencies for the Fiscal Year Ending September 30, 1989 and for Other Purposes, established the schedule for the third solicitation. The request for proposals was issued on May 1, 1989 with proposals due no later than 120 days after issuance of the request. The Secretary of Energy is to make project selections no later than 120 days after receipt of proposals. The framework of CCT-III is currently being developed. This solicitation includes five major objectives: 4-11 PROPOSER Table 4-2 CCT-II Projects PROJECT Southern Company Services, Inc. Birmingham, AL Southern Company Services, Inc. Birmingham, AL Southern Company Services, Inc. Birmingham, AL Southern Company Services, Inc. Birmingham, AL Combustion Engineering, Inc. Windsor, CT Combustion Engineering,|Inc. Windsor, CT Combustion Engineering, Inc. Windsor, CT The Babcock & Wilcox Company Alliance, OH Southwestern Public Service Company Amarillo, TX Demonstration of the Chiyoda Thoroughbred-121 Flue Gas Desulfurization Process Advanced Wall-Fired Combustion Techniques for Reduction of Nitrogen Oxides Selective Catalytic Reduction Technology for Control of Nitrogen Oxides Advanced Tangentially-Fired Combustion Techniques for Reduction of Nitrogen Oxides Post-Combustion Dry Sorbent Injection Technology Demonstration Innovative Clean Coal Gasification Repowering Project WSA-SNOX Technology for Cataly- tically Reducing Sulfur Dioxide and Nitrogen Oxides from Flue Gas Demonstration of the SOX-NOX- ROX Box Post-Combustion Flue Gas Cleanup Process Circulating Fluidized Bed Repowering Project Plant Yates Newnan near Atlanta, Georga Plant Hammond Coosa near Rome, Georgia Plant Crist Pensacola Escambia County, Florida Plant Smith Lynn Haven near Panama City, Florida Yorktown, Virginia Springfield, Illinois Niles, Ohio Dilles Bottom, Ohio Amarillo, Texas 4-12 PROPOSERS Passamaquoddy Tribe Thomaston, ME American Electric Power Service Corp. Columbus, OH Bethlehem Steel Corporation Bethlehem, PA The Babcock & Wilcox Company Alliance, OH Pure Air Allentown, PA TransAlta Resources Investment Corp. Calgary, Alberta Canada Otisca industries, Ltd. Syracuse, NY Table 4-2 ( Cont'd ) CCT-II Projects PROJECT Innovative Sulfur Dioxide Scrubbing Systerm for Coal- Burning Cement Kilns Pressurized Fluidized Bed Combustion Repowering Project Innovative Coke Oven Gas Cleaning Coal Reburning for Cyclone Boiler Nitrogen Oxide Control Advanced On-Site Flue Gas Desulfurization Process Low Nitrogen Oxide/Sulfur Dioxide Burner Retrofit for Utility Cyclone Boilers Production of Compliance OTISCA FULE (Coal Water Slurry) and its Combustion in Retrofitted Industrial Boilers 4-13 Thomaston, Maine West Haven, West Virginia Baltimore County, Maryland Cassville, Wisconsin Gary, Indiana Marion, Illinois Syracuse, New York Jamesville, New York Oneida, New York viv Figure 4-4 Otisca Induatlee Lid The Babcock & Combustion Engineering inc. Syracuse NY Wikos Cunpary Niles OH Jameaville NY ulus Bottom O14 ‘Onelda NY Proposers and Sites * continue the Program to satisfy the recommendations of the Special Envoys on Acid Rain; ¢ address meeting future energy needs in an environmentally acceptable manner; ¢ give credit to technologies which reduce greenhouse effects; * give credit to technologies which reduce solid waste; and ¢ demonstrate technologies which use the total national coal resource base. 4.2.4 Clean Coal Technology-IV (CCT-IV) The fourth solicitation is in the planning stage and, as with the previous solicitations, will be consistent with congressional guidance and administration policy. They will include implementing the recommendations of the Special Envoys on Acid Rain, the President’s Task Force on Regulatory Relief and the Innovative Control Technology Advisory Panel (ICTAP). The advice and guidance received from the National Coal Council, potential industrial participants and states will be used to the maximum extent possible. CCT-IV will recognize that technical advances are constantly being made through research and development. The advanced technologies offer the opportunity to expand the range of future coal utilization options making it possible for coal and coal derived fuels to replace oil and gas in a wide range of applications. These advanced technologies are not sufficiently mature to warrant demonstration during the first three phases of the Clean Coal Technology Demonstration Program, but will warrant demonstration in the CCT-IV phase. 4.2.5 Clean Coal Technology-V (CCT-V) CCT-V, also in the planning stage, will complete the demonstration activities necessary to achieve commercialization of the technologies and to gather the data necessary to achieve the complete program goal. CCT-V presents an opportunity to conduct complementary demonstrations of previously demonstrated technologies. These complementary demonstrations will be directed toward increasing confidence and reducing the risk of widespread commercial deployment of technologies. These complementary demonstrations may involve greater industrial participation as the technical risk is reduced and industrial participants may find it easier to attract project funds since financial markets may be more willing to take risks if prior demonstrations of the technology have been successful. Further, CCT-V will have a major emphasis on technology transfer. 4-15 5.0 CLEAN COAL TECHNOLOGY DEMONSTRATION PROGRAM OBJECTIVES The goal of the Clean Coal Technology Demonstration Program is to make available to the United States energy marketplace a number of advanced, more efficient, reliable and environmentally responsive coal utilization and environmental control technologies. The strategy to achieve this goal is to implement a multi-phase program of cost-shared clean coal technology demonstrations at a large enough scale to enable the private sector to confidently make rational domestic and international commercialization decisions. The five separate phases of the strategy are planned to occur sequentially with separate objectives that will, when integrated, achieve this goal. The principal activities to achieve the goal are shown in Figure 5-1. There are, however, a number of programmatic and technical objectives that must be achieved in each phase for the overall program to be successful. These objectives have been classified into six generic areas: management, technical, economic analysis, environment, market analysis and commercialization. 5.1 MANAGEMENT OBJECTIVES The management requirements of the Clean Coal Technology Demonstration Program are somewhat unique as the Program consists of multiple solicitations over a number of years. The normal progression of events in conducting this cost-shared demonstration program are as follows: * solicit expressions of interests from industry for emerging clean coal technology projects; ¢ solicit, select, and negotiate government-industry, cost-shared clean coal technology projects, as funds are made available from Congress; * as a partner and co-funder of the projects, monitor the progress and provide assistance to the industrial participant as requested; * assure that the projects produce useful technical, environmental, operational, performance and economic data to reduce the uncertainties of subsequent commercial scale deployment of the technology; and ¢ ensure that DOE recovers funds it is entitled to under the cooperative agreements. Imbedded in the above events are a number of activities requiring management approaches and systems which must be tailored to the needs of the Program. During the solicitation process, the views of industry, advisory groups (such as the National Coal Council (NCC)) and the public need to be obtained in order to develop Program Opportunity Notices (PONs) or other solicitation instruments which will elicit the maximum participation from industry while being responsive to congressional mandates. Source Evaluation Boards must be established, and evaluation criteria prepared which are responsive to guidance from Congress and the Innovative 5-1 5-1 Figure Clean Coal Technology Demonstration Program Major Milestones on” ag E = 5 < S 3 - Statements of Interest - Program Opportunity Notice - Negotiations - Statements of Interest - Public Meetings - Solicitations - Negotiations - Public Meetings - Solicitation - Public Meetings - Solicitations A Begin Milestone Control Technology Advisory Panel (ICTAP). Upon project selection, programmatic direction and guidance must be provided to the negotiation teams so that prenegotiation strategies and plans, including milestones, can be developed and negotiations expeditiously completed. Contingency plans must be established in cases where successful negotiations cannot be concluded and deselection occurs. Upon completion of successful negotiations, DOE resource requirements and resource deployment must be analyzed for the entire Program. Analyses performed to evaluate Project Evaluation Reports, which provide the basis for a DOE decision on whether a project should proceed to the next phase, must be verified and validated prior to Assistant Secretary/Fossil Energy (ASFE) approval. For those projects designated major projects under DOE Order 4700.1, Project Management System, quarterly reports need to be monitored and reviewed prior to management and administration approval. Finally, a system for tracking the recoupment of federal funds contributed to each project must be implemented. These needs represent only a summary of the more important aspects in managing the $2.5 billion government funded portion of the Clean Coal Technology Demonstration Program. The specific management objectives are as follows: ¢ Select projects from CCT-II solicitation. (1st quarter FY 1990) ¢ Develop negotiation strategy for projects selected as a result of CCT-III solicitation. (2nd quarter FY 1990) ¢ Negotiate cooperative agreements for projects selected as a result of the CCT-II solicitation. (2nd, 3rd, & 4th quarters FY 1990) ¢ Conduct a number of public open meetings to enlist industries’ views on the content of the CCT-IV solicitation. (2nd & 3rd quarters FY 1990) ¢ Develop CCT-IV solicitation strategy using inputs from industry, NCC, ICTAP and others as appropriate and consistent with administration policy and congressional guidance. (2nd quarter FY 1990) ¢ Establish Source Evaluation Board and prepare proposal evaluation criteria for the CCT-IV solicitation. (2nd quarter FY 1990) ¢ Prepare and issue a Program Opportunity Notice (PON) for the CCT-IV solicitation. (3rd or 4th quarter FY 1990) ¢ Select CCT-IV projects. (PON issue date + 240 days) ¢ Prepare comprehensive CCT-II and CCT-II project reports to Congress. ¢ Execute a system for resource management including budget request, program execution plans, personnel actions, travel, contingency reserves, facilities and equipment assigned to the Program. (Continuous) * Maintain a central system for: tracking allowable project costs; analyzing and validating Project Evaluation Reports prior to phase change Continuation Applications; analyzing project overrun potential; and developing financial status and assessment reports on the total Clean Coal Technology Demonstration Program. This system will be compatible with the ETC’s. (Continuous) ¢ Formulate and justify FY 1991 and FY 1992 budgets: FY 1991 Congressional Budget (January 1990) FY 1991 Congressional Authorization/Appropriation Process (February - September 1990) FY 1992 Internal FE budget development (April 1990) FY 1992 Internal Review Budget (IRB) (June 1990) FY 1992 OMB Budget (September 1990) ¢ Maintain and update Clean Coal Technology Demonstration Program Plan. (1st and 4th quarters FY 1990) ¢ Issue Annual Report to Congress presenting the overall status of the Clean Coal Technology Demonstration Program. (2nd quarter FY 1990) 5.2 TECHNICAL OBJECTIVES The technical requirements of the Program center on assessing state-of-the-technology. These assessments are to identify clean coal technology candidates and to evaluate the slate of on-going and selected clean coal technology projects. The objective is to identify opportunities where a solicitation focused on a particular technology or application of the technology would be appropriate to achieve commercial readiness. Further, there is a need to identify R&D opportunities which, if pursued, might enhance market potential and/or accelerate commercial readiness. The specific technical objectives for FY 1990 are: ¢ Update state-of-the-technology assessments to identify clean coal technology candidates, assess their maturity and determine when they might be integrated into the Clean Coal Technology Demonstration Program. (3rd quarter FY 1990) ¢ Identify R&D needs and opportunities that might enhance market potential and/or accelerate commercial readiness in the course of pursuing Clean Coal Technology Demonstration projects. (Continuous) 5-4 ¢ Respond to project specific requirements for unanticipated technical investigations that would increase the probability of establishing technical readiness. (Continuous) ¢ Utilizing the-Clean Coal Technology Demonstration Program data base and related industry information and experience, update risk assessments on the technologies having achieved technical readiness to determine the extent of further demonstration needed. (3rd quarter FY 1990) ¢ Prepare topical reports on selected technical subjects. (Continuous) 5.3 ECONOMIC ANALYSIS OBJECTIVES Economic analysis needs are focused on ascertaining the economic viability of emerging as well as mature technologies. These economic analyses can serve as a screen in evaluating potential clean coal technology candidates. There is a need to identify and analyze the economic barriers that could inhibit the eventual commercialization of the technologies and to identify and verify alternatives to remove or lessen the impact of the barriers. There is a requirement for a data base of publicly available economic, performance and environmental information on the generic clean coal technologies for use in policy analysis and for use by potential commercial users to confidently screen the generic technologies for those which meet their operational requirements. It is the technology owners’ role to retain the project specific information and experience to promote their technology in the commercial market. The specific economic objectives for FY 1990 are: ¢ Applying best available systems analysis tools, update the FY 1989 economic screening analyses on potential Clean Coal Technology Demonstration Program candidates to determine economic viability. (4th quarter FY 1990) ¢ Conduct life cycle, benefit cost and financial analysis on Clean Coal Technology projects on a standardized basis. (Continuous) ¢ Utilize industrial decision models that assist in identifying barriers to commercial replication of the demonstrated technologies. (Continuous) ¢ Integrate data from project specific economic analysis into generic analysis that can be placed in the public sector. (Continuous) ¢ Maintain an integrated data base easily accessed for internal and external use. (Continuous) ¢ Prepare selected economic analyses topical reports. (Continuous) 5-5 5.4 ENVIRONMENTAL OBJECTIVES The Clean Coal Technology Demonstration Program is directed toward the demonstration of technologies which can reduce sulfur dioxide (SO,), and/or nitrogen oxides (NO,) emissions which will meet or exceed NSPS. Environment objectives focus on the collection, validation, analysis and dissemination of environmental performance data to: verify the attainment of environmental goals of the demonstrated technologies; provide data on environmental performances of generic technologies to enable commercial decisions by the private sector; and enable public sector policy evaluations. Further, there is a need to meet the statutory requirements of the National Environmental Policy Act (NEPA) consistent with the Council on Environmental Quality Regulations (40 CFR 1500 et seg.) and the DOE NEPA guidelines (52 FR 47662). The specific environment objectives for FY 1990 are: ¢ Publish a Programmatic Environmental Impact Statement for the Clean Coal Technology Demonstration Program. (lst quarter FY 1990) ¢ Continue the processing of project-specific NEPA documentation on CCT-I, CCT-I and CCT-II projects. (1st, 2nd, 3rd and 4th quarters FY 1990) ¢ Prepare a Programmatic Environmental Impact Statement amendment in conjunction with the CCT-IV Source Evaluation Board, if required. (4th quarter FY 1990) ¢ Determine what information is appropriate for measuring the overall environmental performance of clean coal technologies (air, water, and solid waste considerations). (Continuous) ¢ Work with industrial participants to structure environmental monitoring plans to measure compliance with environmental requirements and environmental performance. (Continuous) ¢ Conduct a technical and environmental assessment of the impact of clean coal technologies on global warming. Investigate strategies and techniques to mitigate emissions which are thought to contribute to global warming. (4th Quarter FY 1990) ¢ Document and disseminate detailed environmental performance data on a project specific basis. (Continuous) ¢ Work with federal and state environmental agencies to reduce regulatory uncertainties that are impediments to the deployment of clean coal technologies. (Continuous) ¢ Integrate project specific data into generic technology environmental performance information. (Continuous) ¢ Maintain an integrated data base easily accessed for internal and external use. (Continuous) 5-6 ¢ Monitor and analyze impact of pending environmental legislation or regulations on the Clean Coal Technology Demonstration Program, clean coal technologies and commercial deployment of the technologies. (Continuous) ¢ Prepare selected environmental topical reports as required. (Continuous) 5.5 MARKET ANALYSIS OBJECTIVES There is a requirement to conduct market analyses to determine the economic, environmental, regulatory and institutional barriers to domestic and international commercialization. This requirement extends to developing mitigation measures and incentive scenarios based on anticipated/proposed legislation and Executive Orders. The results of the President’s Task Force on Regulatory Relief and the special studies of ICTAP will need to be implemented, where appropriate, by the Clean Coal Technology Demonstration Program. The specific market analysis objectives for FY 1990 are: * Update possible institutional/political constraints/sensitivities to the introduction of new technologies and develop mitigation strategies. (Continuous) ¢ Update regulatory and incentive scenarios based on anticipated/proposed legislation and results from the President’s Task Force on Regulatory Relief and ICTAP and evaluate the impact on clean coal technologies in terms of market enhancement and time requirements. (4th quarter FY 1990) ¢ Drawing upon regulatory and incentive analyses, identify market niches for clean coal technologies in the domestic arena. (Continuous) ¢ Evaluate market forces in the international arena and identify potential market niches. (Continuous) ¢ Prepare selected market analysis topical reports as required. (Continuous) 5.6 COMMERCIALIZATION ENHANCEMENT OBJECTIVES It is the role of the technology owners to commercialize clean coal technologies. The government’s role is indirect and supportive of the technology owners. Using information in the public domain, the Clean Coal Technology Demonstration Program’s objective is to build an educated constituency on the technical, economic and environmental advantages of the clean coal technologies within the public and private sectors, both domestically and internationally. There is a requirement to assess the impacts of pending regulatory changes and legislation on the technology owners’ ability to commercialize the technologies, and to inform public policy decision-makers of these impacts. Further, there is a need to assure that technical, economic, environmental and operational performance of generic technologies is available for public 5-7 analysis and decision-making and that the industrial participants are vigorously pursuing commercialization activities. The specific commercialization enhancement objectives for FY 1990 are: *\ Continue technology transfer activities. (Continuous) Develop negotiation strategies for the inclusion of appropriate terms and conditions into the Cooperative Agreements with regard to the handling of intellectual property, and release of non-proprietary data. (1st quarter FY 1990) Prepare and deliver technical papers at professional conferences and symposia. (Continuous) Encourage industrial participants’ generation of public-relations documents on all clean coal technology demonstration projects. (Continuous) Consult with Department of State and Department of Commerce on activities to enhance commercialization potential both domestically and _ internationally. (Continuous) Ensure the technology owners develop and update required commercialization plans and strategies. (Continuous) Conduct an outreach program to actively establish a dialogue and inform environmental groups and other interested parties on the Program’s benefits, activities and plans. (Continuous) Encourage states to take an active role in providing both economic and non-economic incentives for the commercialization of clean coal technologies. (Continuous) Monitor actions by the Environmental Protection Agency and the Federal Energy Regulatory Commission associated with implementing the recommendations of the President’s Task Force on Regulatory Relief and analysis impact on technology owners’ ability to commercialize technology. Complete and distribute topical reports on technology transfer, commercialization issues and incentives. (Continuous) 5-8 6.0 PROGRAM MANAGEMENT 6.1 PROGRAM MANAGEMENT PHILOSOPHY The Clean Coal Technology Demonstration Program is implemented through Cooperative Agreements with the project’s industrial participants. Under this arrangement the industrial participant contributes at least 50 percent of the required funding and is expected to execute and manage the project while the government shares the cost and risk of the project and the retums in accordance with the recoupment provisions of the Cooperative Agreement. The government will monitor the project to assure goals are being met, will assist the industrial participant in its task and may suggest actions but will not direct the technical activities. Mutual agreement between the industrial participant and the government is needed for significant changes such as those impacting cost, schedule, or objectives. The government will enforce the Cooperative Agreement by means of an implementation plan and the use of well defined and project cost baselines. 6.2 PROGRAM MANAGEMENT ROLES AND RESPONSIBILITIES The Clean Coal Technology Demonstration Program is conducted under DOE’s Fossil Energy (FE) Program and is the responsibility of the Assistant Secretary for Fossil Energy (ASFE). Program management responsibility is assigned to the Deputy Assistant Secretary for Coal Technology (DAS/CT), Associate Deputy Assistant Secretary for Clean Coal (ADAS/CC). The DAS/CT concurs on all Clean Coal Technology Demonstration Program strategy and policy, goals and objectives, program plans, program implementation plans, budget requests and resource utilization proposals. The ASFE approves all program plans, program implementation plans, budget requests, project phase changes and is the ultimate decision maker on all programmatic issues. The Headquarter program management organization is shown in Figure 6-1. Specific roles and responsibilities assigned to DOE Headquarters are as follows: ¢ develops overall Clean Coal Technology Demonstration Program strategy and policy, goals, objectives, and budget requests; prepares annual report to Congress; * solicits expressions of interest from industry for emerging clean coal technology projects; ¢ chairs the Source Evaluation Boards; e as funds are made available from Congress, solicits, selects and assists in the negotiation of government/industry, cost-shared clean coal technology projects; * assures compliance with the National Environmental Policy Act (NEPA); * provides programmatic oversight in monitoring Clean Coal Technology Demonstration projects by the ETCs for adherence to cost, schedule and technical performance; 6-1 Figure 6-1 CLEAN COAL PROGRAM ORGANIZATION ASSISTANT SECRETARY FOR FOSSIL ENERGY ASSOCIATE DEPUTY ASSISTANT ‘SECRETARY FOR CLEAN COAL DIRECTOR - OFFICE OF (CLEAN COAL TECHNOLOGY DIRECTOR OFFICE OF ENVIRONMENT AND SYSTEMS GASIFICATION AND UQUEFACTION COAL PREPARATION RESOURCE ANALYSIS ‘SYSTEMS ENGINEERING > ana > NA A A A A A A A A A A A A A A A Aw SRR AAA A AAA AA AAA AA AAA AAA AAA AAA AAA AAA AAA AAA AAA AAAAAA AAA AAA AAA A RA A A A A A A A A A A A A A AAA AA AAA AAA AA AAA A AAA A A A A A A A A A A A AA AA ¢ identifies areas of program coordination between the Clean Coal Technology Demonstration Program and the appropriate Coal R&D programs; * serves as point-of-contact to the Innovative Control Technology Advisory Panel (ICTAP); * develops strategy and policy to assure commercial deployment, including export, of successfully demonstrated clean coal technologies; * coordinates with other federal agencies, states, international, and private organizations an understanding of the Clean Coal Technology Demonstration Program, its projects, and the benefits to be derived from their demonstration, subsequent deployment and potential for export; and * seeks to improve the regulatory and institutional climate to encourage deployment of demonstrated clean coal technologies into the marketplace at a pace consistent with free market decisions. In accordance with the Office of Fossil Energy’s policy of decentralization, the Clean Coal Technology Demonstration Program is implemented in the field by two Energy Technology Centers (ETCs): Morgantown Energy Technology Center (METC) and Pittsburgh Energy Technology Center (PETC). The METC and PETC clean coal organizations are shown in Figures 6-2 and 6-3, respectively. The ETCs will be active participants in many of the objectives discussed in Section 5.0. Further, there are a number of responsibilities that are jointly carried out by Headquarters and the ETCs. These include: * soliciting, selecting and negotiating government/industry cost-shared projects as funds are made available from Congress; and ¢ providing an adequate technology transfer mechanism to assure that the private sector has the necessary access to the data generated from the Clean Coal Technology Demonstration Program. The following responsibilities have been assigned to the ETCs: * monitoring the design, construction and operation of the projects including analyzing Project Evaluation Reports prior to phase change Continuation Applications; ¢ assuring that the projects provide useful technical, environmental, operational, performance and economic data to reduce the uncertainties associated with commercial scale deployment of the technologies; 6-3 KT a AR AAA AAA A A AA AA AAA AAA A AAA AAA AAA A AAA AAA AAA AAA AAR AAR A AAA A A ARR AA A LOO RR AR A A AAA AA A A AA AA AAA AAA A AAR A A A AA AAA A A A ww PPP ae al a a a a al al aa a a a a aS SSO SSS SSE SOS NONE ana > > > Figure 6-2 MORGANTOWN ENERGY TECHNOLOGY CENTER Office of the Director Office of the Associate Directo for Technical Management Clean Coal Projects Division Projects Management Branch RAIRIDADOOOOHOOOOOOOOOOOOOOOOOOCOCOCOCOOCCOCOOCOCOCOCCOOCOCOCCOCCOCOOCOCOCCCCCUU ESSE SESE SE SESE SESE SESE SE SESE SESE SESE SES eee ee ee a a ee a ee ee eh he ee eh ee De Dd DD dD Dd dd > > > dd D> DD DD DDD DD DD dd dd Dd > dd dd dd do dd dd dd do dd > od ddd o> Process & Project Engineering Branch DP ee DD DD DD DD DD DDD DD DD DD DD DD > > > > > ddd DD DD DD DD DD DD DDD > > DD DD DD DDD DD DD > D> Dd > > DD a“ “ a“ a“ “ “ “ “ “ “ « a “ “ Figure 6-3 PITTSBURGH ENERGY TECHNOLOGY CENTER Office of the Director Office of Clean Coal Technology 2.9.9. > o>. dd bd > > bdo 9.6 9.9 9.9.d 9 22d 5:9 ddd Dd bd did 2 > > > > dd > ddd dd 95H 9 dd 9 99 DDD PF D9 dd o> a“ a“ “ a“ a“ “ *« *« a“ Project Implementation | Systems Analysis and Division Evaluation Division > 2.0 dF. bb Pd Dude sd 2 9.9 oF dd) d bdo: 5 8b.) 9.9_2.0.9.9 ¢ developing a technical, engineering and environmental knowledge base from which to make sound policy decisions relating to future clean coal technology initiations and environmental issues so that the public can be provided with information to form a national consensus on the control of pollutants that may contribute to the formation of acid rain; and * monitoring the recoupment of federal funds from assigned projects as required in the Cooperative Agreement. 6.3 RELATIONSHIP OF THE CLEAN COAL TECHNOLOGY DEMONSTRATION PROGRAM TO THE FOSSIL ENERGY R&D PROGRAM The Clean Coal Technology Demonstration Program is conducted under the Fossil Energy Program which also contains a significant research and development component. The Fossil Energy R&D program has three complementary overall strategic goals of: 1. Maintaining reasonable future domestic energy prices by promoting interfuel competition with particular emphasis on: * increasing the attractiveness of coal by improving environmental, technical, and economic performance; and * increasing the number of areas of applications and flexibility of use of coal-based systems. 2. Promoting energy security and stability by increasing the effective resource base for liquid and gaseous fuels (which can substitute for liquid fuels in many applications) through: * enhanced oil recovery; and/or ¢ production of liquid and gaseous fuel replacements from coal and shale. 3. Encouraging international competitiveness of U.S. fuels and energy technologies. The FE Program pursues these strategic objectives by identifying research opportunities and conducting research in extraction, processing, and utilization of domestic fossil fuel resources not being pursued by the private sector because of high-risk/long-term characteristics. The FE Program mission was expanded on December 19, 1985, when Congress directed that DOE conduct cost-shared clean coal technology projects to demonstrate the feasibility of commercial applications of such technologies. The United States government’s support of coal R&D plays a key role in the long-term national energy strategy of ensuring an adequate supply of energy at a reasonable cost. Since the early 1970s, DOE and its predecessor organizations have pursued a coal R&D program 6-6 directed toward increasing the nation’s reliance on its most abundant fossil energy resource while improving environmental quality. The Coal R&D Program is broadly based and contains long-term, high-risk research that supports development of innovative concepts for a wide variety of coal technologies through the proof-of-concept stage. This research is aimed at improving the economics of using coal, improving the environmental performance associated with its use, and increasing its convenience of use by conversion to lower-cost substitutes for oil and natural gas. The Coal R&D Program includes research in control technologies, combustion systems, coal liquefaction, coal gasification, coal preparation, gas stream cleanup, heat engines, alternative fuels, magnetohydrodynamics, fuel cells and waste management. There is significant synergism between the Clean Coal Technology Demonstration Program and the Coal R&D Program. The Clean Coal Technology Demonstration Program builds upon the Coal R&D technology data base and goes beyond the existing R&D program to demonstrate the commercial feasibility of the most promising coal concepts emerging from the nation’s research and engineering laboratories. For example, pressurized fluidized-bed technology has emerged from the government and industry R&D program, and its demonstration is being financed through cost-shared arrangements under CCT-I and has been selected for further scale-up demonstration under CCT-II of the Clean Coal Technology Demonstration Program. The Coal R&D Program provides a basis for some of the design and testing to support the demonstrations. As problems are identified during the demonstration of technologies, the Coal R&D Program can develop information for their solution. Further, the projects may serve as a test bed for verifying solutions to technical questions at a scale unattainable in the laboratory. The mission of the Oil, Gas and Shale Technologies (OGST) R&D Program is to advance extraction and processing technologies for hydrocarbon resources in order to increase secure domestic energy supplies, especially those which can provide liquid transportation fuels. The OGST Program strategy focuses on extending petroleum and gas supplies through enhanced oil recovery, tar sand, and unconventional gas recovery technology development. This Program also focuses on developing supplies of direct substitutes for petroleum liquids and gas through oil shale and underground coal gasification technology development. The underground coal gasification technology is being demonstrated in CCT-I. 6.4 CLEAN COAL TECHNOLOGY DEMONSTRATION PROGRAM - OTHER DOE HEADQUARTERS ORGANIZATION RELATIONS It is intended that, to the maximum extent possible, ADAS/CC will act as the focal point for communicating and coordinating Clean Coal Technology Demonstration Program business with all appropriate Headquarters organizations. This includes coordination with appropriate offices under ASMA, General Counsel, etc., on environmental, business management and other aspects of the program and Cooperative Agreements negotiated with the industrial participant. 6-7 6.5 EXTERNAL RELATIONSHIPS Relationships with other organizations external to DOE during the execution of the Clean Coal Technology Demonstration Program are desirable and often necessary. These relationships could involve: other federal agencies (Environmental Protection Agency, Department of State, Department of Commerce); state and local governments; industrial research organizations (Electric Power Research Institute, Gas Research Institute); and international organizations. 6.5.1 Other Federal Agencies The Clean Coal Technology Demonstration Program is a national program with high visibility and interest. Successful execution of the Program and its respective projects will produce benefits which can be enhanced through cooperation with other federal agencies. ADAS/CC has the responsibility to establish and maintain, through appropriate DOE organizations, relationships with other federal agencies on matters of mutual interest involving the Clean Coal Technology Demonstration Program. These interactions with other federal agencies could include the following. ¢ Environmental Protection Agency: - consultation on technologies traditionally supported by EPA; - consultation on environmental regulatory considerations; - review of NEPA compliance documents; - consultation on project environmental monitoring plans and subsequent data Treviews; and - environmental policy and regulations affecting future clean coal technology demonstrations and acid rain precursor mitigation. Further, EPA has the following actions stemming from the recommendations of the President’s Task Force on Regulatory Relief as accepted by the President on January 23, 1988: e "New-new” Bubbles - encourage greater use of the recently promulgated policy of allowing emissions trading between two sources subject to certain New Source Performance Standards (NSPS). ¢ Complementary Use of New-new Bubbles and Innovative Technology Waivers - encourage use of these existing emission trading options by utilities that are uncertain whether an innovative clean coal technology will actually achieve NSPS levels before a waiver expires. 6-8 Commercial Demonstration Permits - expand the availability and applicability of the present commercial demonstration permits that allow innovative control technologies for utility boilers to meet less stringent standards than required for other new sources. NO, Control Strategies for Ozone - issue guidance encouraging those areas of the country that can reduce ozone by controlling NO, to examine the potential role of nitrogen oxides (NO,) reductions in place of more expensive volatile organic compounds (VOC) reductions in State Implementation Plans (either through interpollutant emission trades or direct state regulatory actions). Federal Energy Regulatory Commission (FERC) - FERC is responsible for the following actions stemming from the recommendation of the President’s Task Force on Regulatory Relief as accepted by the President on January 23, 1988: - Incentive Rate of Return - establish an incentive rate of return for innovative emission control technologies (coal and non-coal) that recognizes their inherent tisk. FERC already provides this incentive in certain circumstances. - Allowance for Construction Work in Progress - ("Full CWIP") - include construction costs for innovative emission control technologies in the rate base as incurred. Full CWIP is currently provided for pollution control costs and should reduce "rate shock" for consumers. - Accelerated Amortization - apply a 10 to 20 year amortization period to recover the capital costs of innovative emission control technologies. Currently, the typical amortization period is 30 years. Department of State: - negotiation with Canada on approaches for implementing the recommendations of the Joint Report of the Special Envoys on Acid Rain; and - enhancing international trade and improving balance of trade through the export of the products of the Clean Coal Technology Demonstratign Program and United States coal to industrialized nations and lesser developed countries. Department of Commerce: - consultation on improving commercialization probabilities for clean coal technologies; - consultation on maximizing technology transfer; and - enhancing international trade and improving balance of trade through the export of the products of the Clean Coal Technology Demonstration Program and coal. 6-9 6.5.2 State and Local Governments Coal-producing states have a strong interest in the utilization of their indigenous energy resource. Coal provides employment and keeps funds required for energy purchases within a state’s economy. Relationships with state and local governments are important for a number of reasons. ¢ The states will be the beneficiary of the industrial activity associated with the construction and operation of clean coal projects. ¢ A number of states have initiated clean coal funding initiatives. The outcome of these programs could have an impact on the future course of the federal Clean Coal Technology Demonstration Program. Further, these programs offer the potential for increased DOE/state cooperative R&D programs. ¢ Most, if not all, of the selected projects will require state and/or local environmental permits for construction and operation. Close coordination with the states on environmental matters should facilitate the implementation of the projects. ¢ States are active participants in seven clean coal technology projects selected in CCT-I and three projects selected under CCT-II. These are shown in Table 6-1. 6.5.3 Industrial Research Organizations Industrial research organizations play roles both as current or potential participants in the Clean Coal Technology Demonstration Program. Program support is provided by the Electric Power Research Institute (EPRI) in areas such as coal/oil coprocessing, advanced combustors, fluidized bed combustion and control technology and the Gas Research Institute (GRI)in gas reburning and sorbent injection. The participation of EPRI and GRI is also shown in Table 6-1. 6.5.4 International The Clean Coal Technology Demonstration Program has contacts with the international community. For example, a number of the selected projects involve the use of foreign technology or foreign financial participation. Canadian interest in this Program will likely be high since it affects transboundary air pollution concerns and recommendations addressed in the Joint Report of the Special Envoys on Acid Rain. Further, the international community is a potential trading partner for the clean coal technologies and for United States coals. The availability of demonstrated clean coal hardware can give the United States a substantial marketing advantage overseas. Worldwide consumption of coal is expected to increase by more than one-third between now and the year 2000, primarily because of increased coal-fired electric generating capacity. As in the United States, growth in the demand for coal by many industrialized and developing nations will likely be accompanied by increasing environmental concerns. The improved coal technologies 6-10 Table 6-1 Clean Coal Technology State and Institutional Participation Electric Gas Power Research Research State Institute Institute CCT-I Tidd PFBC Ohio Demonstration Project - American Electric Power Service Corporation LIMB Demonstration Ohio Project Extension - Babcock & Wilcox Co. Advanced Cyclone Combustor Pennsylvania Demonstration Project Coal Tech Corp. Gas Reburning/Sorbent Illinois 4 Injection Demonstration Project - Energy and Environmental Research Corp. Prototype Commercial Ohio x Coal/Oil Coprocessing Project - Ohio Ontario Clean Fuels, Inc. Advanced Slagging Combustor New York, x Utility Demonstration Project Ohio TRW, Inc. Cleaned Coal Combustion X Tests Project - Combustion Engineering Inc. 6-11 Table 6-1 (cont.) Clean Coal Technology State and Institutional Participation State ICCT Demonstration Program for Post Combustion Dry Sorbent Injection Technology - Combustion Engineering Co. 5 MWe Demonstration Ohio of SO,-NO,-RO, Box Process - Babcock & Wilcox Low NO,/SO, Burner Illinois Retrofit for Utility Cyclone Boilers - TransAlta Resources Investment Corp. Chiyoda Thoroughbred-121 Flue Gas Desulfurization Unit Southern Company Services Inc. Advanced Wall-Fired Combustion Technique for Reduction of Nitrogen Oxides Southern Company Services Inc. Selective Catalytic Reduction Technology for Control of Nitrogen Oxides Southern Company Services Inc. Advanced Tangentially-Fired Combustion Techniques for Reduction of Nitrogen Oxides Southern Company Services Inc. WSA-SNOX Technology for Ohio Catalytically Reducing Sulfur Dioxide and Nitrogen Oxides Combustion Engineering Inc. 6-12 Electric Power Research Institute Gas Research Institute being developed and demonstrated in the United States will be able to meet the environmental objectives of the international community. Further, since the clean coal projects will provide commercial-scale performance data using United States coals, the potential exists to link United States coal exports and United States technologies in a way that enhances the competitiveness of both. The "packaging" of United States coal and the technologies to use it cleanly and efficiently can become an important by-product of the Clean Coal Technology Demonstration Program. This international market, if pursued successfully, could lead to a reduction in the United States balance of trade deficit. 6-13 7.0 PROGRAM FUNDING HISTORY AND BUDGET Public Law 98-473, Joint Resolution Making Continuing Appropriation for Fiscal Year 1985 and For Other Purposes provided that $750 million from the Energy Security Reserve be deposited and retained in a separate account established in the Treasury of the United States. This account was entitled the "Clean Coal Technology Reserve." On December 19, 1985, Congress passed Public Law 99-190, An Act Making Appropriations for the Department of the Interior and Related Agencies for the Fiscal Year Ending September 30, 1986, and for Other Purposes. Included in this act were provisions for funds to conduct cost-shared, clean coal technology projects for constructing and operating facilities demonstrating the feasibility of future commercial clean coal applications. These demonstration projects comprise the first phase of the program, Clean Coal Technology-I (CCT-ID. This law made available a total of $397.6 million for the Clean Coal Technology Demonstration Program. These funds were distributed over a three year period: $99.4 million in FY 1986; $149.1 million in FY 1987; and $149.1 million in FY 1988. Funding is provided from the $397.6 million for contracting, travel, and ancillary costs incurred by DOE for implementation of this Program. On March 18, 1987, the President sought the full amount of the government’s share of funding recommended by the Joint Envoys on Acid Rain. This funding is to provide $2.5 billion for demonstration of innovative clean coal technologies over a 5-year period. Public Law 100-202, An Act Making Appropriations for the Department of the Interior and Related Agencies for the Fiscal Year Ending September 30, 1988, and for Other Purposes, signed December 22, 1987, provides funds to conduct cost-shared Innovative Clean Coal Technology (ICCT) projects to demonstrate emerging clean coal technologies that are capable of retrofitting or repowering existing facilities. The ICCT projects represent the second phase of the Program. This law made available a total of $575 million for the Program: $50 million in 1988 and $525 million in FY 1989. Of the $50 million, $18.512 million was set aside for Program Direction and $2.232 million was set aside for the Small Business Innovation Research Program. The remaining funds, $29.256 million, were made available for award under a Program Opportunity Notice (PON) released on February 22, 1988. The FY 1989 Appropriations Act (P.L. 100-446) reduced the FY 1989 appropriation for the ICCT solicitation from $525 million to $190 million, with advanced appropriations of $135 million in FY 1990 and $200 million in FY 1991. An additional $575 million was appropriated in FY 1990 for CCT-II. Outlays in FY 1989 for ICCT were limited to $15.5 million. In FY 1990, DOE is requesting advanced appropriations of the remaining $1.2 billion—$600 milion for CCT-IV for FY 1991 and $600 million for CCT-V for FY 1992 so that the full $2.5 billion, five-year program may be realized in support of the recommendations of the joint United States and Canadian Envoys on Acid Rain. The $575 million appropriated for FY 1990 for Clean Coal Technology/Innovative Clean Coal Technology-III will be available in 7-1 FY 1990. A summary of the Clean Coal Technology Demonstration Program funding is shown in Table 7-1. The advanced appropriations discussed above also represent an unusual feature of the Clean Coal Technology Demonstration Program and are not provided for in the R&D programs. Advanced appropriations give added credibility to the Clean Coal Technology Demonstration Program for participants, whereas year-to-year funding of the Program would make planning difficult. €-L Table 7-1 Clean Coal Technology Demonstration Program Funding Profile CCT -| CCT - Il CCT- Ill CCT -IV CCT -V TOTALS Fiscal Years ($ in millions) 1986 1987| 1988 1989 1990 1991 1992 $99.4 $149.11$149.1 $50 $190 $135 $200 $575 $600 $99.4 $149.11$199.1 $190 $710 $800 $600 ~<t— Special Envoys' Program ——> $397.6 $575 $575 $600 $600 $2747.6 APPENDIX A CLEAN COAL TECHNOLOGY-I PROJECT DESCRIPTIONS Appendix A CLEAN COAL TECHNOLOGY-I PROJECT DESCRIPTIONS 1. American Electric Power Service Corporation (TIDD PFBC Demonstration) The project objective is to build and operate a 70-MW, pressurized fluidized-bed combustion (PFBC) combined-cycle powerplant demonstrating that this new coal-burning technology will permit the burning of high sulfur coal to produce electricity in a more economical and efficient way than is commercially available, while meeting or exceeding stringent U.S. environmental Standards. PFBC is a clean coal technology that can burn high sulfur coal in an environmentally superior manner, that is, the emissions of SO, and NO, are held within current environmental limits. Unlike conventional technologies, combined cycle PFBC provides for increased electric generation efficiency through a combined gas and steam cycle. High pressure in the process permits hot gases from the combustor, after cleaning, to operate a gas turbine-generator. Gases from the combustor pass through high efficiency cyclones to Temove approximately 99 percent of the solids in the gas stream before entering the gas turbine. The flue gas from the gas turbine exhausts through an economizer, an electrostatic precipitator, and a stack. 2. The Babcock & Wilcox Company (LIMB Demonstration Extension) The objective of the project is to test a variety of coals and sorbents to demonstrate the limestone injection multistage burner (LIMB) process as a retrofit system for simultaneous control of sulfur and nitrogen oxides in the combustion process. Project goals for LIMB are to demonstrate up to 60-percent NO, and SO, reductions. Additionally, using the Coolside duct injection (Coolside) Process, a base of sorbent and one coal will be tested to demonstrate in-duct sorbent injection, upstream of the humidifier and precipitator, to show SO, removals of up to 80 percent. This project will be conducted at Ohio Edison’s Edgewater Plant in Lorain, OH, on a commercial, 105-MW, boiler. The present EPA-sponsored project will test only one coal and sorbent combination for the LIMB process. The DOE project will demonstrate the LIMB process with multiple coal and sorbent combinations to show the general applicability of the process using medium-and high-sulfur coal. The DOE project will also demonstrate the Coolside process using high-sulfur coal on a commercial scale. Until now, the Coolside process has been demonstrated only at the 0.1-MW and 1-MW scale. 3. Coal Tech Corporation (Advanced Cyclone Combustor Demonstration) The project demonstrates an advanced horizontal cyclone combustor with integral sulfur, nitrogen, and ash control systems. Air is mixed with fuel in standard burners or combustors that are attached to the outside walls of the boilers. The burning mixture is then discharged into the boiler, heating water in the tubes to produce steam. The Coal Tech combustor, which will replace a standard burner, also mounts on the outside wall of the boiler, mixes coal, sorbent (limestone) and air, provides ignition, and removes ash before discharging the hot combustion products to the boiler. The 30-MMBtu-per-hour combustor is approximately 5 feet in diameter and 8 feet long. The specific objective is to demonstrate an air-cooled cyclone, pulverized coal combustor of an advanced design to show that 90 percent of the coal ash can be retained and rejected, that NOx emissions can be held to 100 parts per million and that SO, emissions can be reduced by up to 90 percent. If successful and implemented, boiler slagging and acid rain precursor emissions would be reduced, and additional high-sulfur U.S. coal could be used in an environmentally acceptable manner. 4, Energy and Environmental Research Corporation (Gas Reburning/Sorbent Injection Demonstration) This project is to conduct three full-scale utility demonstrations to show that the combustion of gas reburning and sorbent injection can reduce NO, emissions by 60 percent and SO, emissions by 50 percent from pre-NSPS boilers, If successful, the project will demonstrate a process and equipment that could be easily retrofitted to about 900 U.S. utility boilers (tangentially-fired, wall-fired, and cyclone-fired). This project would also make high-sulfur U.S. coals more usable and would reduce SO, and NO, emissions. This project will demonstrate the gas reburning/sorbent injection process (GR/SI) on three different boilers representing three different combustion configurations. . A tangentially-fired, 80-MW, boiler owned by Illinois Power Company and located near Hennepin, IL. This boiler has burners mounted at the comers and directs the burning coal and air toward points just off the center of the boiler. . A wall-fired 117-MW, boiler owned by Central Ilinois Central Light Company and located near Bartonville, IL. This boiler has burners that direct the burning air/coal into the furnace in a direction that is perpendicular to the wall in which the burners are mounted. . A cyclone-fired 40 MW, boiler owned by City Water Light and Power Company located in Springfield, IL. This boilers has a combustion system that is external to the boiler, and the hot combustion products enter the boilers after the A-2 combustion is complete. 5. Energy International Inc. (Underground Coal Gasification Demonstration) This project will demonstrate that underground gasification of steeply dipping subbituminous coal beds is a cost-effective, reliable, and environmentally acceptable alternative to conventional mining with subsequent surface gasification. The specific objective of this project is to conduct a commercial-scale demonstration of steeply dipping bed underground coal gasification to provide synthesis gas for a small, commercial ammonia and urea plant. The demonstration facility will operate for 12 months, gasifying 1,200 tons of Wyoming coal per day to produce 65 million standard cubic feet per day of product gas. The gas will be used to produce 420 tons of ammonia per day. The feedstock gas for the ammonia plants will be produced by using four UCG modules operating simultaneously. 6. City of Tallahassee (Circulating Fluidized-bed Combustion Repowering Demonstration) The objective of this project is to demonstrate the use of a scaled-up circulating fluidized-bed combustor (CFBC) by replacing an existing gas- and oil-fired boiler at the Hopkins station with a 250 MW, advanced CFBC boiler. The new combustor will be designed to fire West Virginia bituminous coal and will produce steam to drive an existing turbine generator. 7. Ohio Ontario Clean Fuels, Inc. (Prototype Commercial Coal/Oil Coprocessing) The project objective is to build a grass-roots prototype, commercial coal/oil coprocessing plant to convert high-sulfur, high-nitrogen, bituminous coal land poor-quality petroleum residues to clean liquid fuels, using ebullated-bed reactor technology. Coal/oil coprocessing yields liquid fuels that are low in sulfur, nitrogen, and trace metals, and high in heating value. These liquid products can be used directly as a clean-burning boiler fuel or further processed in a conventional petroleum refinery to produce transportation fuels. Nitrogen (in the form of ammonia) and sulfur are recovered as byproducts, thereby avoiding their introduction into the atmosphere as SOx and NO,. Hydrocarbon gases are also collected as byproducts in the form of liquefied petroleum gases (LPG). 8. Colorado-Ute Electric Association, Inc. (NUCLA CFB Demonstration) The objective of this project is to demonstrate the feasibility of circulating fluidized-bed (CFB) combustion technology and to evaluate the economical, environmental, and operational benefits of CFB steam generators on a utility scale. A-3 Three small, coal-fired, stoker-type boilers at the Colorado-Ute Nucla Station were replaced with a single CFB steam generator capable of driving a new 74-MW, turbine generator. Extraction steam from this turbine-generator will power the three existing turbine generators of 12 MW, each, The majority of other existing plant equipment is also being utilized to minimize costs and to demonstrate the suitability of CFB technology for retrofit and life extension of existing units. During the two year test period, the plant will be operated like any other commercial power plant, feeding power into the electrical grid. 9. TRW Inc. (advanced Slagging Coal Combustor Utility Demonstration) The project’s objective is to demonstrate an advanced slagging coal combustor at a scale suitable for utility application. The project will involve converting an existing utility boiler from oil to coal, while meeting environmental standards and without derating the unit. This project will extend the demonstration of a slagging coal combustor from the small industrial boiler demonstration (40 MMBtu per hour) to a full-scale utility boiler retrofit demonstration, converting oil-firing to coal-firing using four 160-MMBtu-per-hour combustors and controlling NOx, SO,, and particulate emissions to meet environmental standards both economically and without derating the boiler. A boiler in an Orange and Rockland Utilities power plant located at Stony Point, NY will be Tetrofitted with four combustors, including pulverized coal and limestone feed systems, slag handling and particulate filter systems, and modification of heat exchange and gas flow systems. During the design phase of the Orange and Rockland project, coal-burning tests and calcined limestone recycle tests will be conducted at TRW’s industrial-scale slagging combustor test facility located in Cleveland, OH. 10. Foster Wheeler Power Systems, Inc. (Clean Energy IGCC Demonstration) This project will demonstrate the technical, environmental, and economic performance of an advanced integrated gasification combined-cycle system in a repowering/cogeneration application at the integrated commercial-scale. The system will utilize IGT’s U-Gas process (fluidized bed gasifier) with hot gas cleanup. An integrated gasification combined-cycle powerplant will be designed to convert high-sulfur coal into electric power and steam in an environmentally acceptable manner, while offering a significant reduction in capital and operating costs over conventional coal-based technologies with flue gas cleaning. The proposed project concept is based on the U-Gas goal-gasification process with limestone injection for sulfur removal. Hot particulate removal will be accomplished by a zinc-ferrite sulfur removal process. The product, low Btu gas, will be combusted in a gas turbine with a steam generator to recover residual heat. A-4 11. | Combustion Engineering Inc. (Clean Coal Combustion Tests) The Combustion Engineering Inc. proposal would extend an ongoing coal cleaning program sponsored by the Electric Power Research Institute, the research arm of the electric utility industry. It would add combustion testing of coals that had been cleaned by advanced processes in EPRI’s Coal Cleaning Test Facility at Homer City, Pennsylvania. Small scale combustion testing would be done first, with selected coals then test-fired in commercial scale 200-MW boilers. The project would take 36 months. 12. United Coal Company (Coal Waste Recovery) United Coal proposes to demonstrate how fine particles of low sulfur coal can be removed form a mine waste disposal pond. The refuse slurry will be removed from the impoundment and pumped through a microbubble flotation device where the small coal particles will be separated from the waste. After drying, the recovered coal would be in the form of a low ash, low sulfur granular form. The project will take place over a two-year period at the Sharples Coal Facility in Logan City, West Virginia. 13. Western Energy Company (Advanced Coal Cleaning Process) The Western Energy Company proposes a novel coal cleaning process to improve the heating value and reduce the sulfur content of wester coals. Typical western coals may contain moisture as much as 25 to 55 percent of their weight. The high moisture and mineral content of the coals reduces their heating value to less than 9000 Btus per pound. The Western Energy process would upgrade the coals, reducing their moisture content to as low as one percent and producing a heating value of up to 12,000 Btus per pound. The process also reduces sulfur content of the coals, which can be as high as 1.5 percent, to as low as 0.3 percent. Western Energy’s project will be conducted at a 50 ton per hour unit adjacent to a Montana Power Company power plant in Colstrip, Montana. A-5 APPENDIX B CLEAN COAL TECHNOLOGY-I PROJECT DESCRIPTIONS Appendix B CLEAN COAL TECHNOLOGY-II PROJECT DESCRIPTIONS 1, American Electric Power Service Corporation (Pressurized Fluidized Bed) The proposer intends to repower two commercially operating 150 MW, pulverized coal-fired electric generating units of early 1950’s vintage by replacing the two boilers with a single pressurized fluidized bed (PFB) combustor/gas turbine module capable of generating 330 MW,,. The net thermal efficiency of the repowered plant will be about 38% (with SO, and NO, control); this compares with the present efficiency of 36.5% (without SO, and NO, control). Specific performance objectives when buming high sulfur (4%) coal are expected to result in greater than 90% sulfur retention and less than 0.3 Ib. NO, emissions per million Btu. The project is based on more than 10 years of development work by the proposer on PFB technology and will build upon the experience gained from the 70 MW,. Tidd PFB Demonstration Plant currently under construction under the first Clean Coal Technology solicitation. The units to be repowered are located at the Philip Sporn Plant in Mason County, West Virginia. 2. Bethlehem Steel Corporation (Coke Oven Gas Cleanup) This proposal involves retrofitting the existing coke gas cleaning plant (coal chemical plant) at the Bethlehem Steel Sparrows Point (Maryland) steel plant which consists of two coke batteries. Currently, the coke oven gas (COG) from the smaller of the two batteries is recycled directly to the coke ovens without chemical recovery or cleanup. The COG from the larger of the two batteries undergoes both chemical recovery and cleanup prior to its use as a fuel gas in various plant operations. Under the proposed project, the COG would be cooled using a recirculating liquor with a (closed) indirect cooling tower thus eliminating the benzene and other emissions associated with the atmospheric final gas cooling tower now in use. Ammonia and H,S would be removed by absorption into an ammonia liquid solution with subsequent steam stripping of the combined H,S and ammonia vapors. This combined stream is then passed to a system where the ammonia is catalytically destroyed (i.e., converted to H, and N,) and a portion of the H,S is oxidized to SO, for input to the Claus plant as a combined H,S/SO, stream. The COG that streams from both coke batteries would be processed with this system. 3. Combustion Engineering, Inc. (Dry Sorbent Injection) This project is a demonstration of three dry sorbent injection technologies: In-Duct Injection, In-Duct Spray Drying, and Convective Pass Injection for flue gas desulfurization. The technologies involve injection of a calcium-containing sorbent either into the convective pass of the furnace or into the duct between the air preheater and the particulate control device. The sulfur dioxide in the flue gas reacts with calcium sulfite and calcium sulfate, which are removed in the particulate control device along with fly ash. This 180 MW, demonstration involves the retrofit of Virginia Electric and Power Company’s Yorktown Plant Unit 2 in York County, Virginia. The objectives of this program are (1) to demonstrate reduction in sulfur oxide emission by fifty percent or greater using these technologies, and (2) to provide technical economic, environmental, and operating data to support commercialization of these technologies by the electric power generation industry. 4, Combustion Engineering, Inc. (Gasification Repowering) This project will demonstrate Combustion Engineering’s pressurized, airblown, entrained-flow coal gasification repowering technology on a commercial scale. The syngas will be cleaned of sulfur and particulates and then combusted in a gas turbine (40 MW,) from which heat will be recovered in a heat recovery steam generator (HRSG). Steam from the gasification process and the HRSG will be used to power an existing steam turbine (25 MW,). The proposed project is to be demonstrated at the Lakeside Generating Station of City Water, Light and Power, Springfield, Illinois. The selected site with associated characteristics and costs includes repowering an existing steam turbine to produce 65 MW, via the combined cycle mode. The process will remove about 12 tons per day of sulfur from a daily consumption of 480 tons of high sulfur (2.5%) Illinois No. 5 coal, a reduction efficiency of over 99%. NO, is expected to be reduced by over 80%. 5. Combustion Engineering, Inc. (WSA-SNOX) The proposed project is to demonstrate the WSA-SNOX technology for catalytically removing both SO, and NO, from flue gas and producing a saleable byproduct, concentrated sulfuric acid. No sorbents are used, consequently, waste byproducts which normally result from their use are not formed. Two catalytic reactors are used to first remove NO, by converting it to N, in an SCR reactor and then to oxidize the SO, to SO,. The SO, is subsequently hydrated and then condensed as H,SO, in the WSA tower. The 35 MW, demonstration will be conducted by retrofitting an 100 MW, existing power plant, Ohio Edison’s Niles Station Boiler No. 2 in Trumbull County, Ohio. The objective of this project is to demonstrate the WSA-SNOX technology on an electric power plant firing high sulfur Ohio coal. A reduction efficiency of 90% or more for both SO, and NO, is expected. The demonstration will feature full-scale components and modules. 6. Otisca Industries, Ltd. (Coal-Water Slurry Production and Combustion) The purpose of the proposed project is to demonstrate the manufacture, storage, handling, and utilization of an ultra clean coal water slurry, known as Otisca Fuel. The core of the manufacturing process for Otisca fuel is the Otisca-T Process, which consists of reducing the raw particle size to effect the releases of mineral matter from the coal, and recovering the ultra clean coal via a selective agglomeration process that employs pentane as the agglomerating agent. The pentane is removed from the recovered ultra clean product coal and reused. Less than 0.25 weight percent pentane remains with product coal. The mineral matter and pyrite remain in the aqueous phase and are removed from processor water by settling. This process is claimed to remove virtually all the pyritic sulfur and a significant quantity of the mineral matter from virtually any coal, while recovering over 95% of the input coal Btu’s in the product coal. The Otisca Fuel will be retrofitted to industrial boilers that are used for the production of steam. The proposed program will support the conversion of up to seven industrial boilers in the central New York state area (Syracuse, Jamesville and Oneida) from their existing configuration, i.e., the burning of oil, gas, or high sulfur coal, to one that allows the combustion of Otisca Fuel. 7. Passamaquoddy Tribe (SO, Control for Cement Kilns) The Passamaquoddy Tribe intends to demonstrate a scrubbing system for removing SO, emissions from existing coal-burning cement kilns. The project features the Tribe’s "Recovery Scrubber", which can reduce SO, emissions by over 90%, uses kiln waste dust as the scrubbing reagent, produces a recycle stream for feeding to the kiln and two potentially saleable byproducts (potassium-based fertilizer and distilled water), and generates no new wastes. The demonstration involves retrofit of the Tribe’s cement plant, Dragon Products Company, which is located in Thomaston, Maine. The demonstration will treat the entire gas stream from the cement kiln, which has a capacity of 470,000tons/year of cement clinker. By-product recovery will be demonstrated through the use of a heat exchanger/evaporator. B-3 8. Pure Air (Advanced Limestone Scrubber) This retrofit project is for a commercial scale advanced limestone scrubber flue gas desulfurization system. A single, 529 MW, absorber module will clean the flue gas from four existing boilers. The system design will use a high velocity, cocurrent flow absorber with direct injection of pulverized limestone. The system design includes a new, and innovative, single-loop process which produces commercial gypsum, using in-situ forced oxidation accomplished by a rotary air sparger. A novel waste water evaporation system will be evaluated that potentially eliminates water disposal/treatment problems associated with the use of high chloride content coals and essentially provides no water discharge. A cyclic reheater will be used to reduce the operating costs normally associated with stream reheat. The overall goal of the project is to demonstrate that the innovative features of the proposed approach combined with by-product gypsum sales will result in a system capable of 90% or higher SO, capture at a cost that is 50% lower than that which can be achieved by currently available FGD systems. The proposed demonstration site is the Northern Indiana Public Service Company’s Dean H. Mitchell Station located in Gary, Indiana. 9. Southern Company Services, Inc. (Chiyoda Thoroughbred-121) The proposed project is for the demonstration of the Chiyoda Thoroughbred-121 flue gas desulfurization process. This process uses a unique absorber design known as the jet bubbling reactor which combines limestone FGD reactions, forced oxidation and gypsum crystallization in one process vessel. As a result, the process is mechanically and chemically simpler than conventional FGD processes and can be expected to exhibit lower cost characteristics. As part of the demonstration, innovations to this process will be evaluated to determine whether costs can be reduced further, including the use of fiberglass reinforced plastic absorber, elimination of flue gas reheat and a space absorber module, and gypsum stacking to reduce waste management costs. The ability of this technology to remove particulates will also be evaluated. A 2.9% sulfur coal will be used for the demonstration which will be conducted by retrofitting Georgia Power Company’s 100 MW, Yates Newman Plant Unit 1, near Atlanta, Georgia. Project objectives include the demonstration of 90% SO, control at high reliability with and without simultaneous particulate control. 10. Southern Company Services, Inc. (Selective Catalytic Reduction) This retrofit project is for the purpose of demonstrating that a combination of combustion modification technology and Selective Catalytic Reduction (SCR) provides the most cost effective B-4 means of reducing nitrogen oxide emissions from power plants. The demonstration will focus on the application of SCR to high sulfur coals. The demonstration plant will be located between Units 5 (75 MW,) and 6 (320 MW,) of Gulf Power Company’s Plant Crist near Pensacola, Florida. This location allows access to flue gas from approximately 3% sulfur coal under a variety of different NO, and particulate levels. Once SCR has been demonstrated to operate economically on high-sulfur American coals, it will represent a technology which has the capability to obtain 90% reduction of NO, emissions for utility and industrial boilers. The technology can potentially be applied to all types of boilers, including cyclone-fired boilers which cannot be easily retrofitted with other developing No, control technologies. 11. Southern Company Services, Inc. (Tangential-fired NO, Control) The project proposed by Southern Company Services will demonstrate three advanced NO, control technologies for retrofit applications to tangential-fired, pulverized-coal boilers: (1) advanced overfire air which consists of deep stage high rate air injection, (2) low NO, concentric fired systems, and (3) advanced tangential-fired systems. The advanced NO, control technologies will be sequentially applied to a single tangential-fired boiler at Unit 2 of Gulf Power Company’s Plant Smith in Lynn Haven, Florida. The proposed 180 MW, demonstration boiler is representative of a large class of tangential boilers. The performance and NO, reduction capabilities of each advanced NO, reduction technology will be evaluated separately and then in combined operation in a logical sequence on a single reference demonstration boiler. The combination is expected to reduce NO, by up to 60%. Each technology will be tested for at least three months under typical dynamic boiler operating conditions. This will ensure an accurate, comparative measure of the long-term NO, reduction capabilities of each technology under typical operating conditions. 12. Southern Company Services, Inc. (Wall-fired NO, Control) Southern Company Services, Inc., intends to demonstrate three advanced NO, control technologies for retrofit applications to wall-fired, pulverized-coal boilers. The three No, control technologies are Advanced Overfire Air (AOFA) which consists of deep stage high rate air injection, second generation low NO, burner (LNB), and LNB with AOFA. The advanced NO, control technologies will be sequentially applied to a single furnace, sub-critical, wall-fired boiler at the Georgia Power Company’s Hammond Plant Unit 4 at Rome, Georgia. The proposed 500 MW, demonstration boiler is representative of a large class of wall-fired boilers. The performance and NO, reduction capabilities of each advanced No, control technology will be evaluated separately first and then in combined operation on the same demonstration boiler. The combination is expected to reduce NO, emission by up to 60%. Each technology will be tested for at least 3 months under typical dynamic boiler operating conditions. This will ensure an accurate, comparative measure of the NO, reduction capabilities and performance characteristics of each of these technologies. 13. | Southwestern Public Service Company (Circulating Fluidized Bed Repowering) Southwestern Public Service Company (SPS) is proposing to repower an existing 256 MW, steam turbine generator at the Nichols Station Power Plant located near Amarillo, Texas using a circulating fluidized bed (CFB) boiler. This repowering project is intended to demonstrate the use of a scaled-up CFB boiler in order to promote commercialization of larger size CFB boilers than are presently available. The boiler will generate 1,800,000 Ibs/hr of steam of 2005 psi and 1005°F. The preheater will be of the heat pipe type - a relatively new innovation in utility boiler applications. The CFB is scheduled to burn Wyoming and New Mexico subbituminous coal. The largest CFB boiler now under construction is the Combustion Engineering boiler for 150 MW, lignite-fueled unit at Texas-New Mexico Power’s (TNP) plant. SPS’s proposed demonstration is approximately 1.6 times larger than the TNP boiler. There will be a 2 year test program after which the facility will continue to operate commercially. For the repowered facility, SO, and NO, will be controlled by 70% and over 80%, respectively. 14. The Babcock & Wilcox Company (Cyclone Reburning for No, Control) The objective.of this project is to demonstrate that coal can be used as a reburning fuel for reducing nitrogen oxides on a coal-fired cyclone boiler. Reburning technology is the only in- furnace No, control technology that has been shown to be technically feasible for cyclone boilers. A coal reburning retrofit will be designed, fabricated and installed in Wisconsin Power & Light Company’s Nelson Dewey Plant Unit #2 which is located along the Mississippi River in Cassville, Wisconsin. Pilot scale testing and mathematical modeling will be utilized in the retrofit design. A successful demonstration of the coal reburning technology could result in achieving a 50% NO, reduction with no resultant decrease in boiler efficiency. This technology is expected to be applicable to all cyclone boilers larger than about 80 MW,. B-6 15. The Babcock & Wilcox Company (SOX-NOX-ROX Box Post-Combustion Flue Gas Cleanup) This project is a post-combustion flue gas cleanup demonstration of combined removal of SO,, NO, and particulates. Ammonia and a calcium-based sorbent are injected upstream of a high temperature baghouse. The sorbent reacts with SO, and is removed in the baghouse. In the presence of the selective catalytic reduction (SCR) catalyst, No, is reduced by NH, to nitrogen and water. Particulate removal is accomplished in the baghouse using high temperature bags. It is estimated that SO, removals of about 50% or more can be achieved with NO, removals of 90% and particulate removals exceeding 99% in a single unit. This SOX-NOX-ROX Box concept will be demonstrated by retrofitting a 5 MW, slipstream of flue gas at Ohio Edison’s R.E. Burger Station in Belmont County, Ohio. 16. Transalta Resource Investment Corporation (Low No,/SO, Burner) For this project, TransAlta proposes to retrofit and demonstrate a low NO,/SO, (LNS) burner and a coal pulverizer system on the 33 MW, unit/cyclone boiler at Southern Illinois Power Cooperative’s Marion Plant in Marion, illinois. Two LNS burners, each rated at 200 million Bt/hr, will be retrofitted to the existing Babcock & Wilcox cyclone boilers, and are expected to reduce both NO, and SO, emissions. The LNS Burner is a pulverized-coal-fired entrained-flow system with staged combustion. Calcium in the form of limestone added to the coal is used to capture the sulfur. in the combustion process, a large fraction of the coal is gasified, thus freeing the sulfur and creating the conditions for sulfur capture in a solid calcium-sulfur form. Also, the gaseous nitrogenous species, including NO,, are converted to harmless molecular nitrogen. Finally, in the boiler, air is added to complete combustion and to obtain full heat release from the coal fuel. The very high combustion temperatures in this process melt the coal ash for its removal as slag. APPENDIX C STATE-OF-THE-ART CLEAN COAL TECHNOLOGY CANDIDATES 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 12.0 13.0 Table of Contents Conventional Flue Gas Desulfurization Processes Advanced Combustors ......... 0. cee cece eaee Advanced Flue Gas cleanup ...............2005 Advanced Coal Cleaning ...............0000e Alternative Fuels... 2... 0... cece eee eee eee Coal Liquefaction ............ ccc cece eee Atmospheric Fluidized Bed Combustion.......... Pressurized Fluidized Bed Combustion........... Underground Coal Gasification ................ Heat-Engines ..... 60sec ccc cece mses vnseees Industrial Processes 11... . cece cece eee eee Appendix C Appendix C STATE-OF-THE-ART OF CLEAN COAL TECHNOLOGY CANDIDATES 1.0 Conventional Flue Gas Desulfurization Processes New Source Performance Standards (NSPS) of 1979 mandate that a typical new plant is to be equipped with particulate matter control, such as an electrostatic precipitator (ESP) or a baghouse, and a flue gas desulfurization (FGD) system capable of removing 70 percent (low sulfur coal) to 90 percent (high sulfur coal) of the sulfur dioxide (SO,) generated. There are a number of FGD process designs, including wet, dry, nonregenerable and regenerable. The utility industry, historically, has had a strong preference for nonregenerable, calcium-based, wet slurry processes that produce a waste product for disposal, i.e., the lime/limestone scrubbing process. In this process, the SO, in the flue gas comes in contact with, and chemically reacts with, a recirculating lime or limestone slurry in the scrubber to form a precipitate or sludge. The reacted lime or limestone slurry from the scrubber goes to a reaction tank where calcium sulfite and calcium sulfate precipitates as hydrated solids upon addition of fresh lime or limestone. To avoid the buildup of solids in the system, a portion of the slurry from the reaction tank is sent to a solid liquid separator which may be a centrifuge, filter or a holding pond. The waste sludge composed of calcium sulfite, calcium sulfate and fly ash is withdrawn to a disposal area while the liquor is returned to the process. Makeup water is added to compensate for evaporation and water lost with the waste sludge. The cleaned flue gas is reheated above its dew point and released through the stack. A pulverized coal-fired power plant with lime/limestone flue gas scrubber capability can be applied to all new and replacement power plants. The technology is technically retrofittable to existing pre-1979 NSPS power plants. FGD can be used by industrial boilers in much the same way as in utilities, although the choice of specific FGD technologies may be different. Various conventional lime/limestone FGD systems are in operation on a number of industrial boilers. The most significant environmental emission of lime/limestone scrubbing is solid waste. Currently, solid wastes from a typical 500 MW plant using 2.5 percent sulfur, 12 percent ash, midwestern bituminous coal amount to about 160,000 tons/yr of ash and 135,000 tons/yr (dry basis) of FGD waste (impure gypsum). Quantities of these materials will vary according to the sulfur and ash content of the feed coal. A number of improvements to the basic process described above are needed in order to improve SO, removal and increase system availability. Varying the chemical composition of the limestone FGD system or the use of organic additives can improve SO, removal. Other improvements in FGD have been realized--scrubber redundancy (required to ensure availability) and elimination of reheat cycle and system reliability concerns. These have been substantially reduced or mitigated through extensive operating experience and technical improvements. CLEAN COAL TECHNOLOGY CANDIDATES 2.0 Advanced Combustors A coal combustor is a device mounted on a boiler or heater in which coal and oxygen are combined and combusted to produce usable heat. An advanced combustor is a device that is capable of controlling or removing undesirable constituents, such as sulfur and nitrogen oxides and particulate matter, from coal during the combustion process. Although these combustors are intended primarily for retrofit applications, they also are appropriate for new facilities that because of their compact size and flexibility with respect to various coal types. Advanced combustors include the advanced slagging combustor (ASC), the limestone injection multistage burner (LIMB), and the low-NO, burner. 2.1 Advanced Slagging Combustors The slagging combustor concept is not completely new. These high intensity burners were used in the United States between 1940 and 1970. Most slagging combustors were retired in the early 1970s because of poor performance characteristics with respect to SO, and nitrogen oxides (NO,) control. Advanced slagging combustors have incorporated improved techniques to reduce NO, and SO, formation in the combustion chamber. The advanced slagging combustors control; (1) particulate emissions by converting ash into molten slag which is removed before injection into the boiler or heater, (2) NO, formation by staged combustion to reduce temperatures, and (3) sulfur oxides (SO,) formation by injecting alkali compounds during combustion. Removal efficiencies for SO, are 90 percent for high- and medium-sulfur coals and 70 percent for low- sulfur coal. NO, reductions of 50 to 70 percent relative to wall-fired, pulverized-coal combustors are achieved. Ash removal efficiencies in the combustor range form 90-95 percent. Because of the high SO, reduction, flue-gas cleanup usually is not required. ASC technology has a wide range of applications. It is appropriate for any size utility or industrial boiler in either new or retrofit applications. Because of its high-ash removal capability, it can be used not only in coal-fired boilers but also in oil- and gas-fired. Of the various methods for burning coal currently being developed (i.e., circular and cell burners, spreader stokers, underfed stokers, water-cooled and vibrating stokers, travelling grate stokers, and cyclone combustors), the cyclone combustors have the highest potential to use the most abundant and relatively inexpensive surplus of high-sulfur, high-ash, low-fusion-temperature coals. Recent developments have shown that cyclone combustors can operate using staged combustion to control the formation of NO, during the combustion process. In addition, the formation of SO, in these combustors is effectively reduced by the injection of alkali-compounds. Status of Technology DOE’s Advanced Combustion Technology Program consists of three developmental phases. In the first phase, near-term slagging concepts appropriate to large industrial and utility applications, are being developed through proof-of-concept stage. Toward that end, a slagging combustor was Cc-2 developed that has been operated on three experimental units with capacities of 1, 10, and 50 million Btus per hour. Additionally, a number of new longer-term, innovative combustor concepts (e.g., pulsed combustion, wet oxidation, and vortex containment combustion) are being considered. The second phase concentrates on the selection, development, and system integration of smaller size concepts for light industrial, commercial, and residential applications. The third phase involves development of systems marketable for retrofit, industrial, commercial, and residential areas, and the development of combustors for retrofitting pre-NSPS, coal-fired utility and large industrial boilers to reduce environmental emissions. Under the CCT-I Program, DOE selected the following two projects on the commercial demonstration of combustor technology: 1. Advanced Cyclone Combustor Demonstration Project (proposed by Coal Tech Corporation), which will utilize a slagging combustor with sorbent injection into the combustor. The objective of this project is to demonstrate that 90 percent of the coal ash can be retained and rejected, NO, emissions can be held to 100 parts per million, and SO, emissions can be reduced by up to 90 percent using an air-cooled, pulverized coal combustor. The process generates both steam and electricity in the 30 MMBtu/hr combustor. Currently, the project is in Phase 3 (operation and data collection) wherein the objective is to conduct parametric studies for 900 hours on 2 percent and 4 percent sulfur pulverized coal. 2. Advanced Slagging Coal Combustor Utility Demonstration Project (proposed by TRW, Inc.), which will utilize an advanced slagging coal combustory with NO,, SO, and particulate control capabilities. The purpose is to demonstrate the operation of an advanced slagging coal combustor for bituminous coals (sulfur content, 0.7-2.5 percent) at a scale suitable for utility applications. At present, the project is in Phase 1 (design and permitting). 2.2 Limestone Injection Multistage Burner The limestone injection multistage burner (LIMB) technology is representative of the furnace injection process. It is a variant of the ASC discussed previously in that it combines sorbent injection feature (for the direct capture of SO, from the combustion gases) and the low-NO, burner feature (for the staged combustion and control of NO,) with the ASC, however, LIMB does not have a cyclonic ash removal system. As a result, all of the ash is carried from the boiler as fly ash in the fuel gas. Removal efficiencies for both SO, and NO, are as high as 60 percent. Following SO, control which is accomplished by injecting a dry sorbent into the boiler, the sorbent is removed along with fly ash in the existing particulate removal equipment, either by an electrostatic precipitator (ESP) or a baghouse. The LIMB process is applicable to any size utility or industrial coal-fired boiler. It is also applicable to coal of any sulfur content. New boilers can be designed using this technology, C-3 however, the practicality of LIMB as a retrofit technology depends on its compatibility with existing boiler systems. LIMB is an emerging technology that is currently undergoing research and development at the bench, pilot, prototype and demonstration plant levels. The thrust of ongoing research is to identify those factors that govern the performance so that the removal efficiency can be optimized. Status of Technology Recent pilot-scale tests conducted on the LIMB process revealed that the sorbent (for SO, control) could not be injected through the multistage burner, which was originally designed to control both SO, and NO, formation. Instead, separate sorbent injection points higher in the furnace cavity were required to control SO, emissions. Based upon the results from the recent pilot-scale tests conducted by Babcock and Wilcox, the LIMB process has evolved so that sorbents other than limestone are used for furnace injection and the injectors point differs from the multistage bummer. These sorbents (e.g., hydrated lime, hydrated dolomite) offer the potential for increased removal without some of the operational problems observed with the original concept. Because of the many similarities to the original process, the new concept continues to be referred to also as LIMB. LIMB was one of the eleven projects selected by the DOE under the Clean Coal Technology-I (CCT-I) Program. Co-sponsors with DOE include the State of Ohio, Babcock and Wilcox and Consolidation Coal Company. With retrofit applications in mind, the demonstration project is to focus on two activities. The first part is an extension of the ongoing LIMB project where additional tests are to be conducted to determine the applicability of the technology using different types of coals and sorbents. The second part is to evaluate Consolidation Coal Company’s "Coolside" process for SO, control. Both activities are expected to last until December 1990. 2.3. Low-NO, Burner Low-nitrogen oxides burners are non-slagging combustors and are replacements for standard burners, however, their only role is to reduce NO, emissions. These burners reduce NO, emissions by promoting a more gradual mixing of fuel and air to reduce flame temperature and by using a richer fuel-air mixture to reduce oxidation of nitrogen in the fuel. Low-NO, burners provide an increased level of nitrogen oxides control with reported removal efficiencies of 45-60 percent. Of the four candidate boiler types considered for retrofit applications (i.e., tangentially- fired, wall-fired with circular burners, wall-fired with cell burners, and cyclone-fired), pilot-scale tests have been successfully completed on all boilers except cyclones. Low-NO, burner technology is not applicable to this furnace design. c-4 Low NO, burners have a wide range of applications. They are appropriate for any size utility or industrial coal-fired boiler in either new or retrofit applications. Further, coal of any sulfur content can be used with low-NO, burners. Status of Technology © Low NO, burners are currently available for tangential- and wall-fired boilers with standard circular burners. Although low-NO, burners are commercially available for retrofit applications, Operating experience with them is rather limited. As a result, retrofit cost and performance data for this control technology are still preliminary. Additional tests on these burners are necessary to assess how operating parameters such as load following, combustion efficiency, and partial plant loading are affected. Currently, there are no specific projects on non-slagging combustors under the CCT-I Program, however, the following three projects are included in the CCT-II Program: 1. Demonstration of advanced wall-fired combustion techniques for the reduction of nitrogen oxide emissions from coal-fired boilers in a 500MW boiler (proposed by Southern Company Services, Inc.), The emission of NO, is expected to be reduced by up to 60 percent. 2. Demonstration of advanced tangentially-fired combustion techniques for the reduction of nitrogen oxide emissions from coal-fired boilers in a 180MW boiler (proposed by: Southern Company Services, Inc.). The emission of NO, is expected to be reduced by up to 60 percent. 3. Demonstration of a low NO,/SO, burner on a fully retrofitted 33MW cyclone boiler (proposed jointly by Transalta and the Illinois Department of Energy and Natural Resources). The emissions of both NO, and SO, are expected to be reduced by up to 90 percent. 3.0 Advanced Flue Gas Cleanup Flue gas cleanup methods encompass a family of devices that are applied to remove various pollutants, such as sulfur oxides (SO,), nitrogen oxide (NO,), and particulate emissions from the flue gases released as products of fuel combustion from a given source. Advanced flue gas cleanup processes are represented by: spray dryer which can remove both SO, and NO,; the reburning process which is primarily used to remove NO, but can also reduce SO, depending on the fuel characteristics; sorbent injection systems for SO, removal only; selective catalytic reduction process for NO, removal only; and wet/dry flue-gas desulfurization processes used primarily for SO, but can also remove particulates depending upon sorbent characteristics. C-5 3.1 Spray Dryer The spray dryer process is representative of the dry, throw away processes. The process utilizes a mixture of lime and recycled solids. The slaked mixture in the form of slurry is injected into the spray dryer. Slurry atomization is accomplished by a rotary device or by nozzles; the degree of atomization and the vessel dimensions are such that the water in the slurry evaporates before it strikes the wall. The flue gas passes through the spray dryer and electrostatic precipitator or a fabric filter and then the stack. Part of the dried solids (ash plus reaction product collected both in the fabric filter and the spray dryer) is recycled to increase lime utilization while the remainder becomes by-product for reuse or disposal. It is also feasible to remove NO, using this system. This is accomplished by raising the spray dryer’s outlet temperature to 175-195°F (normal temperature is 150-168°F) and adding caustic soda (NaOH) to the primary lime sorbent. SO, removal efficiencies as high as 95 percent have been achieved and NO, removal efficiencies have reached 55 percent. Total suspended particulates are 0.0081b/10° Btu. The process is applicable to any size new utility or industrial coal-fired boiler or for retrofitting old boilers. Status of Technology The spray drying is generally considered as an established technology and has reached the commercialization level for use with low-sulfur coals, however, with high-sulfur coals, the process is in a relatively early stage of development. More compact and somewhat less complex . than the wet limestone scrubbers, the spray dryer’s economic advantages over limestone scrubbers decrease with increasing coal sulfur content as a result of higher reagent costs. Combustion Engineering, Inc., was selected, under the CCT-II Program, to demonstrate three dry sorbent injection technologies in a 180MW utility plant; in-duct spray drying, in-duct injection and convective pass injection. One of the major objectives of this program is to reduce SO, emissions by 50 percent or greater by using these technologies. 3.2 Reburning Reburning also known as fuel staging, is a promising post-combustion technology for the removal of NO, only. Fuel is passed around the main combustion zone and injected above the main burners to form a reducing zone in which NO, is converted to reduced nitrogen compounds. About 15-20 percent of the fuel is injected into this reburning zone. Although any fuel can be used for reburning, pilot studies performed in the United States indicate that fuels with little or no fuel-bound nitrogen can achieve greater NO, reductions. In this way, natural gas is probably the most effective reburning fuel because of low fuel-bound nitrogen. , Reburning technology is applicable to any size utility or industrial coal-fired boiler. It is also applicable to coal of any sulfur content. This process can be used in new boilers as well as in retrofit applications. Natural gas reburning is applicable to a wide range of wall-fired, tangentially-fired, and cyclone-fired boilers. Sorbent injection techniques for the control of SO, C-6 can also be used in conjunction with reburning as a unit process, known as gas reburning sorbent injection (GR-SI) process. Low cost calcium-based sorbents can be injected at one or more locations as the combustion gases pass from the radiant furnace through the convective process to the air heater. The sorbent contained in the fly ash is removed from the flue gas in an existing precipitator or baghouse. The GR-SI process provides an alternative technology, suitable for retrofit applications, to conventional wet flue-gas desulfurization process. Status of Technology Recent tests conducted by the Gas Research Institute (GRI) on a 25kw benchscale and a 3MW pilot-scale furnace show a capability of 60 percent NO, reduction when using 15-20 percent natural gas as a reburning fuel. An additional benefit of using natural gas as a reburning fuel is overall emissions of SO, and ash are reduced by 20 percent. Using oil or coal or reburning fuels results in less NO, reduction and an increased carbon content in the fly ash. Tests conducted on a 600Mw oil/coal dual-fuel fired unit in Japan using low nitrogen oil as a reburning fuel achieved 50 percent NO, reduction. DOE has selected Energy and Environmental Research Corporation to conduct a large-scale demonstration of the GR-SI technology under the CCT-I Program. The cosponsors include the Gas Research Institute and the Illinois Department of Energy and Natural Resources. This demonstration is the first commercial scale application of the GR-SI technology on a utility. The goal of the approximately five-year program is to demonstrate the technical and economic feasibility of the GR-SI technology at three host sties in Illinois. The program is designed to achieve up to 60 percent nitrogen oxide and 50 percent or more SO, reduction burning a blend of high sulfur coals. Phase 1 (design and permitting) activities are scheduled for completion in late 1988 followed by initiation of Phase 2 (construction and start-up) activities. Under the CCT-II Program, DOE has selected Babcock & Wilcox to demonstrate NO, control technology using the concept of reburning by demonstrating a coal reburning technique for controlling NO, from a cyclone boiler at Wisconsin Power & Light Company’s Nelson Dewey Plant. It is estimated that up to 50 percent NO, reduction can be achieved with no resultant decrease in boiler efficiency. 3.3 In-Duct Sorbent Injection In-duct sorbent injection involves injection of dry or slurried sorbents into the duct area between the air preheater and particulate control device. The direction of the injection is concurrent with the gas flow, and as the cone of spray expands, the gas within the cone cools and the SO, is rapidly absorbed by the spray droplets. Several different in-duct injection process concepts have been proposed. They primarily differ by the injection sorbent used: dry sodium compounds, powdered lime hydrates in conjunction with water or steam, and lime slurries. The mode of spraying and the position of the spray mechanisms in the duct may also vary depending on the process. The injected sorbent removes SO, while in suspension in the duct work, and in the particulate control device. The reaction by-products are collected along with the normal fly ash. C-7 Currently, calcium-based sorbents in a wet, dry, or semi-wet mode are being tested in the flue-gas ducts of eastern and midwestern utilities. Typical SO, reductions are in the range of 55 to 75 percent. The volume of solid waste generated is considerably increased, however, the waste is dry, nontoxic, and easily disposable. Status of Technology Three sorbent injection processes are currently being developed with the funds from DOE: (1) the confined-zone dispersion process developed by Bechtel Corporation involves injection of pressure-hydrated dolomitic-lime slurry close to the center of the duct through a dual-fluid nozzle. As the cone of spray moves downstream and expands, the gas within the cone cools and SO, is rapidly absorbed by the still-liquid spray droplets. The process requires a sufficient length (about 50-100 feet) of straight ductwork following the sprays. Tests are currently being conducted at a 7MW plant to achieve 50 percent SO, removal from 2.3 percent sulfur coal; (2) the in-duct scrubber (IDS) process, developed by General Electric Environmental Services, Inc., is similar to a conventional spray dryer except that the reaction vessel is eliminated. Instead, a rotary atomizer sprays slaked-lime reagent directly into the flue-gas duct. Through a cooperative agreement with American Electric Power and Ohio Power Company, General Electric is developing a 12MW pilot-plant which utilizes 4.3 percent coal from southern Ohio; and (3) the Hydrate Addition at Low Temperature (HALT) developed by Dravo Corporation involves the injection of calcium hydroxide (hydrate) into a duct with humidification and/or temperature control of the flue gas. Initial results show that 60-70 percent SO, removal can be achieved upstream of a fabric filter with a 3.2 percent sulfur coal. This process is being demonstrated at Ohio Edison’s Toronto station at the SMW equivalent scale. The application of HALT process, described above, is currently being deployed by the Energy & Environmental Research Corporation under the CCT-I Program. The project uses a combination of both reburning and sorbent injection technologies. The NO, reduction is achieved through burning whereas SO, emissions are controlled by sorbent injection. The goal is to reduce NO, and SO, emissions by 60 percent and 50 percent, respectively, from pre-NSPS boilers. Phase 1 (design and permitting) activities are scheduled for completion in late 1988 followed by initiation of Phase 2 (construction and start up) activities. Under the CCT-II Program, Combustion Engineering, Inc. and Babcock & Wilcox were selected to demonstrate in-duct sorbent injection technologies for the following two projects: 1. Combustion Engineering, Inc. will demonstrate three dry sorbent injection technologies: in-duct injection, in-duct spray drying, and convective pass injection at their 130MW plant in Yorktown, Virginia. A key objective is to demonstrate SO, reductions of 50 percent or greater by using these technologies. 2. Babcock & Wilcox Company will demonstrate combined removal of SO,, NO,, and particulates from industrial and utility coal-fired boilers. SO, removal is accomplished using ammonia and either a calcium- or sodium-based sorbent injected upstream of a high C-8 temperature baghouse. In the presence of the selective catalytic reduction (SCR) catalyst, NO,, is reduced by NH, to nitrogen and water. The sorbent reacts with SO, and is removed in the baghouse. It is estimated that SO, removal of about 50 percent or more can be achieved with NO, removals of 90 percent and particulate removal exceeding 99 percent in a single unit. 3.4 Selective Catalytic Reduction Selective catalytic reduction (SCR) is a flue-gas treatment process for removal of NO, only. In utility applications, an SCR system is placed between the economizer and air preheater of a power plant, where temperatures are suitable for the chemical reactions involved. Inside the SCR system, ammonia is first mixed with flue gas and then passed through a catalytic reaction chamber. At the catalyst surface, NO, is reduced by ammonia to form elemental nitrogen and water. The advantages of SCR include high reductions in emissions of nitrogen oxides: relatively simple equipment, no by-product; and, because it is a dry process, minimal temperature loss. Reductions of nitrogen oxides of 50-80 percent are generally realized although 90 percent has been attained under carefully controlled conditions. The SCR process should be applicable to any size utility or industrial coal-fired boiler that burns either low or medium-sulfur coal. With high-sulfur coal, however, solid and liquid sulfates are deposited in the preheater, where they interfere with heat transfer, cause corrosion, and plug passes, resulting in increased pressure drop. Contamination of ash with ammonia by-products is also possible, which may increase waste disposal costs or hamper ash use. These problems are less pronounced with low-sulfur coals. SCR systems are well-suited to being installed on new boilers but can also be retrofitted to existing boilers. Status of Technology Of all the various post combustion NO, control technologies currently being developed, selective catalytic reduction system has reached a high degree of demonstrated success. To date, several successful power plant tests have been performed on coal-fired power plants. In general, selective catalytic reduction systems are more expensive than combustion modification processes. Certain improvements are needed in the areas of process control, extension of catalyst life, cost reduction, and elimination of ammonia leakage in order to make this NO, control technique commercially viable by 1990. DOE, under the CCT-II' Program, selected the following three projects for commercial demonstration of NO, reductions through the utilization of selective catalytic reduction: 1. Southern Company Services’ project was selected to demonstrate the control of NO, emissions from high sulfur, coal-fired boilers using a combination of selective catalytic reduction and combustion modification technology at the Gulf Power Company’s plant c-9 near Pensacola, Florida. It is estimated that up to 90 percent reduction of NO, emissions can be achieved for utility and industrial boilers by the application of this technology. 2. Combustion Engineering will demonstrate the WSA-SNOX technology at Ohio Edison’s Niles. Station WSA-SNOX is a flue gas cleanup technology which catalytically removes SO, and NO,. No sorbents are used and no waste by-products are formed. Two catalytic reactors are used to first remove NO, by converting it to N, in an SCR reactor and then oxidize the SO, to SO;. The SO, is subsequently hydrated and then condensed to H,SO,, which can be sold. A reduction efficiency of 90 percent or more for both SO, and NO, is expected. 3. Babcock & Wilcox will demonstrate its process for the combined removal of SO,, NO,, and particulates from the flue gas. In this process (known as SO,-NO,-RO, box), ammonia, and a calcium- or sodium-based sorbent is injected into the flue gas. NO, removal is accomplished by injecting NH, to selectively reduce NO, in the presence of a catalyst. The choice of sulfur sorbent depends on the site applications. Particulate removal is accomplished in the baghouse using high temperature bags. NO, removals of 90 percent, SO, removals of 50 percent, and particulate removals exceeding 90 percent are possible in a single unit. 3.5 Advanced Flue Gas Desulfurization Pulverized coal-fired boilers for electric utilities in the United States are the predominant source of generating electricity. In order to comply with 1979 New Source Performance Standards (NSPS), a new plant is normally equipped with particulate matter control, such as an electrostatic precipitator (ESP) or a baghouse, and a flue-gas desulfurization (FGD) system capable of removing 10 to 90 percent of the SO, generated. Generally, the FGD system is a wet scrubber. Some advanced scrubber systems (e.g., Bechtel Chiyoda Thoroughbred 121, Dual-Alkali are also being developed for new and retrofit markets. At present, several small-scale utility applications of these processes exist domestically, but wide spread use is predicted through expanded demonstrations of these technologies. 3.5.1 Chiyoda Thoroughbred 121 Process The Chiyoda Thoroughbred 121 (CT-121) process represents an advanced second generation technology which utilizes all the necessary steps for SO, control--absorption, oxidation, neutralization, and crystallization in a single gas-liquid-solids reactor, known as jet bubbling reactor. In the CT-121 process, instead of being sprayed with slurry, flue gas is forced through the reactor vessel containing limestone slurry. The process reverses the conventional approach of removing SO, from flue gas as the absorbent liquid is the continuous phase and the flue gas is the dispersed phase. Through this process modification, high SO, removal rates are achieved without the scaling, plugging and corrosion problems often associated with first-generation wet limestone processes. Typical SO, removal efficiency is greater than 90 percent which is C- 10 controlled by adjusting the sparger pipe levels (devices for forcing flue gas into slurry of reactor vessel). The by-product of this regenerable process is high-quality gypsum. 3.5.2 Dual-Alkali Scrubbing Dual-alkali scrubbing was developed to avoid the problems of erosion, scaling, and a solid deposition found with wet-limestone FGD. In this process, two alkali solutions are used: a clean solution (generally sodium sulfite) in the absorber followed by the addition of lime in the reaction tank to regenerate the spent solution for recycle to the absorber. The resulting calcium sulfite- sulfate sludge is then dewatered and landfilled. Makeup sodium (typically soda ash) is added to the regenerated solution to replace residual sodium lost in the filter cake. The process has a removal efficiency of 90 percent for SO, and is applicable to medium and high-sulfur coals. With low-sulfur coals, the need to increase lime utilization makes this process more expensive than wet-limestone scrubbing. The process can be used for new boilers and for retrofit on old boilers. Status of Technology Dual-alkali scrubbing systems do not have a NO, removal capability. A system with this capability has been developed and tested on a laboratory scale by researchers at the Argonne National Laboratory. The system involves retrofitting a metal-chelate, NO, control technique, into a dual-alkali scrubbing process. Levels of NO, removal ranging from 50 percent to more than 90 percent have been observed for extended periods in the laboratory, while SO, removal has been simultaneously maintained or enhanced. Due to promising laboratory results, pilot scale testing is currently being pursued. Several industrial control technology vendors and chemical service companies have expressed an interest in this process concept. Since 1982, eight units with a total capacity of over 1000MW and equipped with CT-121 processes have been deployed worldwide although only prototype units (23MW - 45MW) are currently operational in the U.S. Under the CCT-II Program, the following two projects were selected by DOE for demonstrating the flue gas desulfurization technology at commercial scale. 1. Southern Company Services has proposed the demonstration of the Chiyoda Thoroughbred-121 process by using a 2.9 percent sulfur coal in a to-be retrofitted Georgia Power Company’s 100MW plant unit near Atlanta, Georgia. Project objectives include the demonstration of 90 percent SO, control at high reliability with and without simultaneous particulate control. 2. The second project pertains to desulfurization of flue gases using a limestone scrubbing system. A joint venture between Pure Air and Mitsubishi Heavy Industries America, Inc., with the cooperation of Northern Indiana Public Service Company, will demonstrate their innovative technology in a 529MW facility located in Gary, Indiana. The overall SO, removal is estimated to be 90 percent or higher at a cost that is 50 percent lower than that which can be achieved by currently available FGD systems. C-11 4.0 Advanced Coal Cleaning Current commercial practices of coal cleaning emphasize physical separation techniques and are limited to removal efficiency of about 10-30 percent of the total sulfur in coal. Sulfur exists in coal in two distinct forms: pyritic sulfur, as small particles of iron pyrite: and organic sulfur, which is chemically bonded to the coal. Each form can comprise 30-70 percent of the total sulfur content, depending on the coal type. Coal also contains other mineral matter, commonly referred to as ash. Several advanced coal cleaning techniques are under development that may, in the long run, yield 30-90 percent sulfur reduction. Advanced coal cleaning techniques have the potential to provide a much cleaner coal which could be utilized in new markets, with significant additional applications to the now dominant utility and large industrial markets. The advanced coal cleaning includes both physical and chemical/biological processes. ADVANCED PHYSICAL CLEANING PROCESS 4.1 Ultrafine Coal Process The ultrafine coal process is based on the phenomenon that electric and/or magnetic fields can be applied to fine coal as a means to separate coal from its impurities. When a mixture of two types of particles is introduced into a system in which at least some of the particles are broken, a differential charge is created. One type of particle is charged positively and the other negatively. Differences in electric charge together with differences in magnetic susceptibility cause the mineral matter and the coal to separate when passed through these fields. In practice, the UFC system includes a "charger" into which the pulverized coal is introduced and subjected to impact and breakage by being accelerated to a high velocity and projected against or along surfaces. The charged particles then exit into a collector, where an electric field is maintained between slowly rotating electrode disks. Alternate disks are maintained at positive and negative potential. The negatively charged inorganic particles are attracted to the positive electrodes and are scraped off in the reject removal zone of the collector. The positively charged coal particles are attracted to the negative electrodes and are scraped off into the project stream. The UFC process is suitable for any size utility or industrial boiler and can be used for new and repowering applications. 4.2 Advanced Flotation Advanced flotation is an extension of the commercially used flotation technique. Both techniques exploit the differences in surface properties between coal and its impurities but differ in process configurations and types of chemicals they use. During the first stage of the two-staged advanced flotation process, rougher flotation cells separate the high-ash, least floatable materials from the coal. The froth product from this rougher stage is further processed in the second stage, when it is reprocessed in cleaner cells, in which a pyrite depressant is used in addition to a coal collector. The froth product of the second stage is low in ash and sulfur and becomes the final product. The rejects form the cleaner cells are combined with the rougher stage refuse and C- 12 disposed of. The advanced flotation process is suitable for any size utility or industrial boiler and can also be used for new and repowering applications. Status of Technology — At present, advanced physical coal cleaning methods of interest are focused primarily on the potential for increased cleaning efficiency of ultrafine coal (finer than 325 mesh). Laboratory float-sink tests indicate the theoretical potential to remove over 90 percent of both ash-forming minerals and pyritic sulfur from ultrafine coal. This is a significant improvement over results with a coarse coal feed. DOE and the Electric Power Research Institute (EPRI) are jointly developing clean coal technologies for testing at the Clean Coal Test Facility operated by EPRI at Homer City, Pennsylvania. The technologies for grinding ultrafine coal and processing or handling the clean product are being considered at the same time. Commercialization of the advanced physical cleanup processes is not expected until the 1990-1995 timeframe. DOE has selected three coal cleaning projects under CCT-I. 1. Combustion Engineering Inc. project is to conduct combustion tests of coals that have been cleaned by advanced processes in EPRI’s Coal Cleaning Test Facility at Homer City, Pennsylvania. 2. United Coal Company’s project is to demonstrate how fine particles of low sulfur coal can be recovered from a mine waste disposal pond using a microbubble flotation device. 3. Western Energy Company’s project is to demonstrate a novel coal cleaning process to improve the heating value and reduce the sulfur content of western coals. ADVANCED CHEMICAL AND BIOLOGICAL CLEANING PROCESSES 4.3, Advanced Chemical Cleaning Process Advanced chemical cleaning processes have the potential to remove 90-95 percent of total sulfur (as well as 95-98 percent of ash) and involve treating the coal with chemicals or solvent refining under high temperature and pressure. As a result, the cost of chemical cleaning is expected to be substantially higher than conventional or advanced physical coal cleaning processes. The Gravimelt process treats coal with a strong alkali at about 660°F wherein the coal sulfides are converted to alkali sulfides and the ash is converted to alkali-aluminum silicates. This process uses molten caustic leaching technology in which finely ground coal particles are exposed to a molten caustic solution that leaches out approximately 90 percent of the coal sulfur and mineral matter from the coal. The cleaned coal is separated from the spent caustic and impurities through water washing and filtration steps. Spent caustic is also separated from contaminants and regenerated for reuse. This process is suitable for any size utility or industrial boiler, with the exception of cycle boilers. Emission removal efficiencies for SO, are 90 percent for both C- 13 medium (2.5 percent) and high (3.6 percent) sulfur coals. No hazardous wastes are produced by this process. 4.4 Advanced Biological Cleaning Process In general, bacterial desulfurization processes require highly specific bacterial cultures having the desired performance characteristics (e.g., sulfur removal, efficiency, growth rate, reliability, in process conditions). In theory, the biological processes offer the potential for complete sulfur removal at ambient or near ambient, operation and low energy requirements. Status of Technology Both chemical and biological processes are being investigated because of their ability to remove the organic sulfur. A number of chemical cleaning techniques are being investigated. Bench scale tests were performed on the component modules of the Gravimelt process and the results have been encouraging. Continued research activities are underway leading to design and construction of a 20 pounds per hour integrated continuously operated system. Current research activities in microbial desulfurization focus on the isolation of naturally occurring bacterial strains. Preliminary bench-scale work to investigate the validity of the mutagenic alteration concept is currently being studied. Other biological approaches involve exploration of non-bacterial systems (e.g., fungal systems for beneficiation of low rank coals). At present, there are no commercial demonstration projects on coal preparation that are included either under the CCT-I or the CCT-II Program. However, the Otisca T process is currently being readied for demonstrating the commercial feasibility of alternative fuels under the latter Program. The process uses pentane to form agglomerates of coal. The process is capable of removing virtually all pyritic sulfur from bituminous coal while reducing their ash content to 2 percent or less. 5.0 Alternative Fuels Alternative fuels include suspensions or slurries of coal or coal-derived solids in water and/or combustible liquid and involve coal-water, coal-oil, and coal-methanol mixtures. Coal-slurry fuels are mixtures of pulverized or micronized coal (less than 200 mesh), a liquid carrier such as water and/or combustible liquid, and additives for viscosity reduction and stability control. The mixtures are 50 percent to 70 percent solids (coal fuel) by weight, 30 percent to 50 percent liquid carriers, and 1 percent chemical additives. The resultant mixture can be transported, stored, and handled in a fashion similar to oil and potentially combusted in hardware designed for coal, oil, natural gas or hardware specifically designed for coal-liquid mixtures. Typically, the coals in the slurries will have been selected or cleaned to levels of sulfur and ash dictated by the particular application. C- 14 Coal in the form of a slurry is pumped under pressure into the burner manifold where it is injected into the combustion chamber. With the proper combustor design, high combustion efficiencies can be achieved. Alternative fuels are being developed for retrofitting existing oil- and gas-designed light industrial, commercial, and residential boilers and furnaces. The earliest market will likely be oil-fired utility and industrial boilers followed by commercial, institutional, residential, diesel, and gas turbine applications. Status of Technology Considerable technological development has been made, both nationally and internationally, for coal-liquid mixture systems. There have been more than 24 coal-oil mixture and coal-water mixture projects in the U.S. and abroad. The majority of the activity has been in the area of fuel development with a lesser amount in the area of combustion. The coal-oil mixture development Program was structured by DOE in 1976 for transferring this technology to private industry which is now actively marketing this fuel. The private sector has focused its efforts on the least risky technology i.e., development of coal-based fuels for utility and large industrial systems of coal and oil design. The Electric Power Research Institute (EPRI) has demonstrated combustion of coal-water mixtures in an industrial boiler (100 MBtu/hr) at the E.I. du Pont deNemours and Company’s Memphis, Tennessee pilot plant. Coal-water mixture preparation plants have been built in Japan, Korea, Italy, Sweden, the United Kingdom, and Canada. Commercial coal-water mixture preparation plants are in place in Sweden and the U.S. The full-scale commercialization of alternative fuels technology for coal-water and coal-oil based fuels is not expected until the 1990-1995 timeframe. It is noted that although none of the thirteen projects selected under the CCT-I Program is an alternative fuels activity, there are projects among the thirteen that will benefit from the planned fuel specification and combustion characterization effort. The Alternative Fuels program under the Office of Fossil Energy (FE), will provide data on fuel handling and feeding and combustion characterization. A recent project (proposed by Otisca Industries), selected under the CCT-II Program, pertains to the manufacture, storage, handling, and utilization of a coal-water slurry fuel (called OTISCA fuel) from Eastern bituminous coal that is high in ash and sulfur content. The project will demonstrate the commercial feasibility of the process in retrofitted industrial boilers for the production of steam. The process claims to remove all the pyritic sulfur and a significant quantity of the mineral matter from virtually any coal. During the 12-month demonstration period, the project will manufacture and use 40,000 tons of OTISCA fuel. 6.0 Coal Liquefaction Coal liquefaction produces useful liquid fuels from all domestic coal resources (bituminous, subbituminous, and lignite). Three processes fall in this category: (1) direct liquefaction; (2) indirect liquefaction; and (3) coal/oil coprocessing. Another process, pyrolysis, is the oldest technique for obtaining liquids from coal and involves heating coal in the absence of air or oxygen to obtain heavy oil, light liquids, gases and char. Typical conversion rates from coal are: 50 percent char, 30 percent liquids, and 20 percent gases. C- 15 6.1 Direct Liquefaction Direct liquefaction converts the complex organic chemical structures found in coal directly to liquid components by hydrogeneration. The ground coal is slurried with a recirculated process- derived oil and reacted under elevated temperatures and pressures. The recirculated oil acts as a fluid carrier and also plays an important role in the chemistry of coal dissolution. The liquefaction reactions can be carried in the presence or absence of catalysts and in a single reactor or in multiple reactor stages. The major potential advantages of direct liquefaction are high thermal efficiency (60-70 percent) and high liquid product yield. The principal disadvantages stem from the severe operating conditions involving coal slurries and the high degree of integration found among process steps. The products have generally aromatic structures because of the structures found in coal and this makes high quality motor gasoline a major product of direct liquefaction. The initial products may contain significant quantities of heteroatoms from the coal which must be removed by careful process adjustments or by known refining/upgrading treatments. Similarly, heavy aromatic compounds that are known to be biologically active may be present in direct liquefaction products which can also be reduced or eliminated by process adjustments or further processing. Direct liquefaction is suitable for modernization of existing refinery or chemical processing facilities. Status of Technology Recent advances in the understanding of coal liquefaction reaction paths and catalyst deactivation mechanisms have resulted in process concepts involving improved process configurations (e.g., staged liquefaction), higher quality recycle solvent compositions and improved catalyst activity and performance. Staged liquefaction is an advanced process that provides improved cost technology. Several processes based on this approach have completed bench-scale development and have been or are being evaluated at the Advanced Coal Liquefaction R&D Facility in Wilsonville, Alabama. More advanced, staged liquefaction technology options are being developed at the bench scale. Four direct liquefaction processes have been tested through the pilot stage: (1) Exxon Donor Solvent, (2) H-Coal, (3) Solvent Refined Coal-I (SRC-I), and (4) SRC-I. Each process was developed in the mid to late 1970s and uses a single reactor stage. As a result of these activities, direct liquefaction can now be considered to be technically ready for commercial demonstration. 6.2 Indirect Coal Liquefaction Indirect liquefaction involves gasification of coal to produce a raw synthesis gas, gas cleanup, water-gas shift reaction to adjust the H,:CO ratio of the synthesis gas, and the liquid synthesis process itself. The liquefaction (liquid synthesis) step is generally less complex from an engineering perspective than direct liquefaction, but the overall process is generally less efficient and less selective to fuel grade liquids. The liquefaction step does not have to deal with coal ash and the products, which are generally aliphatic rather than aromatic, and free of sulfur and nitrogen contamination. The chemical structure of the products can favor production of diesel C- 16 fuels as a major product. Biological activity and potential health effects are not likely to be a problem with the products of indirect liquid synthesis. The principal solid waste form the gasifier is coal ash which can be disposed of in the same manner as coal-fired boiler ash. there are three prominent indirect liquefaction processes; Fischer-Tropsch, methanol-synthesis, and methanol-to- gasoline conversion. — Indirect liquefaction could be used to retrofit facilities having existing coal gasification technology. Liquefaction reactors can be added downstream of the synthesis gas cleanup train, providing a relatively low-cost conversion of coal-derived fuel gas to high-quality liquid fuels. Status of Technology The best known approach to indirect liquefaction is the Fischer-Tropsch technology which is the basis for the largest commercial coal liquefaction facilities in the world. These facilities are operated in South Africa by the South African Coal, Oil and Gas Co., Ltd. (SASOL). African Explosives and Chemicals, Inc. (AECT), also located in South Africa, produces 100 tons/day (T/D) of methanol from coal and is testing its use as a gasoline blend and as an experimental neat fuel. The Tennessee Eastman Co., since 1983, has operated the only coal to methanol plant in the U.S. A single Texaco gasifier processes 900T/D of coal to produce methanol as an intermediate in the production of methyl acetate and acetic anhydride. This project is commercially feasible in the U.S. because of specific project requirements. 6.3 Coal-Oil Coprocessing In coal-oil coprocessing, coal is slurried in residual fuel oil rather than recycle solvent, and both coal and petroleum residuals are converted to high-quality fuels in subsequent processing steps. The immediate benefit of coprocessing is better operating economics because less hydrogen is required and the need for a process-derived recycle solvent is eliminated. it is noted that in most processes for direct liquefaction of coal, solvent requirements have been a big stumbling block. The solvent often was expensive, needed in large quantities, and required a high investment in equipment. From an environmental perspective, removal efficiencies of up to 90 percent and 60 percent are possible for SO, and NO, respectively. Demetalization of greater than 95 percent are feasible from high-metals petroleum residuum. Because of the variety of products (e.g., naptha, mid-distillate, vacuum gas oils and residuum) coprocessing can produce, this technology can be used to supply fuels for a wide range of applications in the utility or industrial sectors. Virtually any size boiler that uses coal, distillate oil, residual oil, or natural gas can use the fuels. The technology can be used in new or retrofit applications. C-17 Status of Technology The Electric Power Research Institute has recently completed Phase 1 of a coal-oil coprocessing program to determine the technical and economic feasibility of coal-oil of this coprocessing to produce high-quality, environmentally acceptable fuel products from poor-quality and low-cost feedstocks. The coals tested were Ohio No. 5/6 coal, Alberta Coal, Illinois No. 6 Coal and a U.S. Gulf Coast lignite. The Ohio Ontario Clean Fuels, Inc. project, Coal-Oil Coprocessing Liquefaction, was one of the thirteen projects selected under the CCT-I Program. The operational data form this project will serve to focus the research and development effort to overcome problems that hinder further advancement of the state-of-the-art of the technology and its optimization for commercial application. At present, the project is in Phase 1 (design and permitting). 7.0 Atmospheric Fluidized Bed Combustion In a fluidized-bed design, coal and limestone are fed into a bed of hot particles (1400-1600°F) fluidized by upflowing air. The SO, formed during combustion is captured as it reacts in the limestone to form calcium sulfate. The relatively low combustion temperature limits NO, formation and reduces ash fusion problems. Atmospheric fluidized bed combustion (AFBC) equipment operates at or near atmospheric pressure. There are two major AFBC systems: the dense or bubbling-bed and the dilute or circulating-bed. They differ in the location of their heat absorption surfaces, feed-stock particle size, and throughput velocities. Bubbling-beds have lower fluidization velocities, around 5-12 ft/sec while circulating-beds have velocities as high as 30 ft/sec. 7.1 Bubbling-bed Combustion The bubbling-bed concept attempts to prevent solids carry-over by maintaining the fuel and inert material within the combustor. The bubbling-bed AFBC consists of a boiler coupled to a combustion chamber that is modified to accommodate the fluidized bed. A relatively dense bed of solids is maintained at the top of the furnace by firing relatively large-size coal and limestone particles and operating at relatively low velocities, as mentioned above. Approximately 90 percent of the combustion and sulfur capture takes place in a bed of dense solids. To control temperatures in the bubbling bed design, a heat sink in the combustion area takes the form of water-wall enclosures and/or in-bed boiler tubes. The steam output is controlled by manipulating bed height, temperature, fuel input, and gas velocity. In order to ensure good combustion characteristics, excess limestone, bottom ash, and certain combustion by-products are removed at frequent intervals. The hot combustion gases are cooled in the upper section of the boiler area. This upper section is high enough to allow escaping particles to fall back to the bed so as to maximize combustion efficiency. 7.2 Circulating-bed Combustion The circulating-bed concept encourages solids carry-over through high velocity air which entrains and returns the solids to the combustor for additional burning. In a circulating-bed system, air injected from below thé bed (i.e., the underbed feed) at high velocity fluidizes fuel and sorbent particles and lifts the burning mass the full height of the boiler, with no distinct boundary of the bed visible. After releasing heat to the water-walls in the boiler and the super heater, the particle-laden combustion gases flow into the hot cyclones. Particles removed by the cyclones are then recirculated to the original combustion chamber, where they mix with fresh fuel and limestone. The flue gas flows through the convective heat transfer section, an air heater, than through fabric filters and out the stack. The long furnace retention time for the fuel and limestone and their continuous circulation allows for complete fuel combustion and the removal of SO,. The circulating fluidized-bed boilers tend to have higher combustion efficiencies (exceeding 99 percent) than the bubbling-bed design. The circulating fluidized beds have a good potential in both the industrial and utility sectors for repowering old coal-fired boilers or constructing new boilers. Coal of any sulfur content can be used for such systems. SO, removal efficiencies of 90 percent and emission rates of less than 0.41b/10° and 0.031b/10° Btu’s have been estimated for NO, and particulates, respectively. Status of Technology Atmospheric fluidized bed combustion technology is commercially available for large industrial boiler applications (200,000 Ibs/hr steam and greater). Commercial units are offered by 19 U.S. boiler manufacturers, and approximately 115 units are either operating or committed to construction. At present, the principal utility applications of AFBC are through retrofit/repowering of existing boilers. Five AFBC demonstration plants are presently in various stages of development: * Northern States Power, Black Dog Station, 125 MW, bubbling-bed AFBC; * Colorado-Ute Electric Association, Nucla Station, 110-MW, Circulating-bed AFBC: * Tennessee Valley Authority, Shawnee Station, 160 MW, bubbling-bed AFBC; ¢ Wisconsin Electric Power, Oak Creek Units 1-4, 500 MW (total), bubbling-bed AFBC; and * Montana-Dakota Utilities Co., R.M. Heskett station, 80MW bubbling-bed AFBC. Under the CCT-I Program, Colorado-Ute Electric Association, Inc. was selected to demonstrate a utility application of a circulating fluidized-bed combustion system at its facility at Nucla C- 19 Station, Colorado. The project will demonstrate the control of sulfur dioxide and nitrogen oxides and other pollutants at lower cost than afforded by add-on equipment or other existing technologies. The operational testing is scheduled to begin in late 1988 for the subsequent 21 month period. Also under CCT-I, The City of Tallahassee was selected to demonstrate the use of a scaled-up circulating fluidized-bed combustor. The new 250 MW combustor will replace an existing gas and oil fired boiler and will be designed to burn West Virginia bituminous coal. Under the CCT-II Program, Southwestern Public Service Company has been selected to repower an existing 256MW steam turbine generator at the Nicholas Station Power Plant near Amarillo, Texas using a circulating fluidized bed (CFB) boiler. This repowering project will demonstrate the use of a scaled-up CFB boiler in order to promote commercialization of larger size CFB boilers than are presently available. The boiler will generate 1,800,000 Ibs/hr of steam at 2,500 psi and 1005°F. For the repowered facility, SO, and NO, will be controlled by 70 percent and over 80 percent, respectively. 8.0 Pressurized fluidized Bed Combustion Pressurized fluidized bed (PFB) combustion technology offers the capability to repower oil and gas-fired boiler units (while switching them to direct high sulfur coal-burning) and to retrofit and/or repower existing coal-fired power plants, and to build new units. A PFB combustor involves the burning of coal in a bed of limestone (calcium carbonate) or dolomite (calcium magnesium carbonate), inside a furnace operated at elevated pressure (8-16 atm); bed temperatures normally are in the range of 1,650°F. The bed material, referred to as sorbent, is fluidized (suspended) by the injection of air at the bottom of the bed. Sulfur dioxide released during combustion of the coal reacts and is captured by the sorbent material. A PFBC system has several advantages, including its smaller size (relative to AFBC), because of a higher operating pressure and capability for modular fabrication and construction. These attributes are believed to make the PFBC concept an economical alternative for power generation, particularly for satisfying incremental load growth. There are three basic concepts of PFBC design: air- cooled boiler; combined-cycle boiler; and turbo-charged boiler. 8.1 Air-Cooled Boiler In an air-cooled boiler system, the bed is cooled by air flowing through tubes in the vessel walls. The hot (1,870°F) pressurized combustion gases exiting the combustion bed are cleaned, mixed with the coolant air, and then used to drive a gas turbine before passing through a waste-heat steam generator to run a conventional steam turbine. This approach, however, may require development of new gas cleanup technology because of the potential for the high-temperature flue gas to foul and corrode the gas turbine. Another problem is the lower-than-optimal heat transfer coefficient within the steam tubes, necessitating larger tubes to equal the output of comparably sized combustors. C- 20 8.2 Combined-Cycle Boiler In the combined-cycle plant, the bed tubes are filled with water that is converted to steam as it cools the bed. This steam is sent to a conventional steam turbine for electricity production or other uses. The combustion gases exit the fluidized bed, are cleaned in a gas cleanup system, and then sent to an expansion turbine where additional electricity is produced. About 75 percent of the electricity is produced in the steam turbine and 25 percent in the gas turbines. Combined- cycle PFBC permits the combustion of a wide range of coals, including high-sulfur coals. The SO, removal efficiencies are about 90 percent. Because of the lower operating temperatures, NO, emission levels are only 0.31b/10° Btu’s, and total suspended particulate levels are 0.031b/10° Btu’s. Combined-cycle PFBC produces a dry, solid waste that is easily disposed of in an environmentally acceptable manner. Prospects for repowering existing facilities are greatly enhanced by the modular approach of PFBC systems. 8.3. Turbo-Charged Boiler In a turbo-charged system, steam is used to cool the combustion chamber, which maintains a pressure on the order of 10-11 atmospheres. An additional heat transfer surface is provided above the bed to generate more steam and cool the flue gas. The superheated steam is sent directly to a conventional steam turbine; the steam cycle generates all the electricity for transmission. The gases exiting the combustion chamber are at a lower temperature (800°F) than in other PFBC systems, making the gas cleanup requirement more flexible. The overall thermal efficiency of the turbo-charged PFBC is expected to be less than the other PFBC systems (37 percent versus 39 percent), but greater than that of the AFBC. Status of Technology The PFB process is not as technically mature as AFB. Significant research and development has been conducted on PFB, and work has progressed to the point where sufficient data are available to design and construct a prototype PFB coal-fired demonstration plant. Under the CCT-1 program, the American Electric Power Service Corporation has been selected to demonstrate a utility application of PFB combined-cycle technology at the Tidd station near Brilliant, Ohio. The project is composed of retrofitting the coal-fired power plant (no longer in use), constructing a 70MW PFB combined-cycle demonstration plant. The goal of the project is to demonstrate that combined-cycle PFBC technology is a cost-effective, reliable, and environmentally superior alternative to conventional coal-fired electric power generation with flue gas desulfurization. At present the first two phases (Phase 1: design & permitting) and (Phase 2; construction and start- up) are underway simultaneously. Phase 3 (operation & data collection) is planned for initiation in late 1990. The experience gained from the Tidd project will be used by the American Electric Power Service Corporation, under the CCT-II Program, to repower two commercially operating 150MW pulverized coal-fired electric generating units by replacing the two boilers with a single PFB combustor/turbine module capable of generating 330MW. The net thermal efficiency of the C-21 repowered plant will be about 38 percent (with SO, and NO, control) as compared to the present efficiency of 36.5 percent (without SO, and NO, control). Specific performance objectives when burning high sulfur (4 percent) coal are expected to result in greater than 90 percent sulfur retention and less than 0.31b/10° Btu’s of NO,. The startup operations are planned for late 1995. 9.0 Fuel Cells Fuel cells directly transform the chemical energy of a fuel and oxidant into electrical energy. Each fuel cell includes an anode and a cathode separated by an electrolyte layer. A hydrogen- Tich gas or hydrogen is fed to the anode and oxygen or air is supplied to the cathode. One of the reactants is disassociated in an electrolyte (e.g., phosphoric acid, molten-carbonate, or solid oxide) into electrons and ions to provide a direct current (DC) to the circuit connecting the two electrodes. Energy conversion is potentially more efficient (40 to 60 percent, depending on fuel and type of fuel cell) because electricity is generated directly in the fuel cell instead of going through an intermediate conversion step. The fuel system efficiency can be increased further in cogeneration by using the heat by-product of the reaction to generate steam or to heat water. Coal is a target fuel for phosphoric acid, molten carbonate, and solid oxide fuel cell power plants. A typical fuel cell system using coal as fuel would include a coal gasifier with a gas cleanup system, a fuel cell to generate electricity (DC), a power processing section to convert DC to alternating current (AC), and a heat recovery system. Fuel cells require highly clean fuel to avoid contamination and degradation of their performance because their tolerance to sulfur, particulate matter, and. other contaminants is very low. Consequently, during operation, emissions of air pollutants, suspended solids, solid wastes, and contaminated waste water are insignificant. Fuel cell technology is applicable to the industrial and commercial sectors and to the electric power generating industry. Fuel cells are especially suitable for repowering applications because of their significantly higher conversion efficiency of fuel to electricity, modular construction, high efficiency at part load, minimum siting restrictions, potential for cogeneration, and low production of pollutants. Status of Technology The development of fuel cells in the U.S. has been underway for the past 25 years for high technology applications such as the space program. During the 1970s, utilities began to investigate fuel cells as an efficient, non-polluting, alternative power generation technology to meet their load growth. Currently, three types of fuel cells using different electrolytes are being developed: (1) phosphoric acid, (2) molten carbonate, and, (3) solid oxide. Phosphoric acid Systems are the most mature of all fuel cell systems, but are not expected to be ready for commercialization until 1990-1995 timeframe. The early commercial phosphoric acid fuel cell power plants are expected to operate on reformed natural gas or distillate fuels. These power plants ultimately may be operated with coal, but major hurdles must be overcome, in particular with regard to system modification of the gas cleanup section. Molten carbonate fuel cell C- 22 technology is in the early development stage and scale-up to full area stacks is in progress. Solid oxide fuel cell technology has been tested in single cells and in a 5k submodule. Molten carbonate and solid oxide fuel cells are not expected to reach commercialization stage until about the year 2000. 10.0 Surface Coal Gasification Surface coal gasification encompasses several processes for converting coal into a gaseous fuel of chemical feedstock. Coal is reacted with either air or oxygen and steam. Heat and pressure break apart the molecular bonds of coal resulting in a combustible mixture of carbon monoxide and hydrogen. If air is used, a low-Btu gas is produced with heating value in the range of 125- 150 Btu/scf. Gasifying coal with oxygen creates a medium-Btu gas with heating values from 270-320 Btu/scf. Medium-Btu gas can be upgraded to a substitute natural gas (SNG) with a heating value of 950-1,000 Btu/SCF, or it can be used as a feedstock to produce various chemicals, such as methanol and ammonia. Both medium- and low-Btu gas can be used as a fuel for integrated gasification combined-cycle (IGCC) power plants, which offer increased efficiency and significantly lower gaseous emissions than conventional coal-fired power plants. Integrated means that the coal gasification and electricity generation processes are simultaneous and synchronized. The four major processes of an IGCC facility are: (1) converting coal (via partial oxidation and gasification) into a fuel gas; (2) cleaning the fuel gas; (3) using the clean fuel gas to fire a gas turbine generator and using the hot turbine exhaust to make steam, which drives .a steam turbine generator; and (4) treating the waste streams generated. The configuration of a specific IGCC facility will depend primarily on the type of gasification technology used. Because of construction and operational considerations, IGCC technology is generally applicable to medium and large plants in the utility sector. Coal of any sulfur content can be used with IGCC systems. An IGCC plant produces about 40 percent of the solid waste produced by a comparable pulverized-coal plant. Removal efficiencies of SO, are 97 percent and emission levels of NO, are 0.081b/10° Btu’s. Particulate emission levels are 0.0011b/10° Btu’s. These levels are all well below New Source Performance Standards (NSPS) limits. Status of Technology Through several pilot scale tests and two commercial-scale demonstration facilities, (120MW Cool Water gasification project in Daggett, California, and 160MW Dow coal gasification project in Plaquemine, Louisiana), it has been demonstrated that IGCC has the potential to generate power economically while minimizing air emissions as well as liquid and solid waste streams. Both these projects employ entrained-bed gasifiers. The Electric Power Research Institute (EPRI) has investigated several other gasifiers for use in the IGCC configuration. These include the Shell, Lurgi Dry Ash, KILNGAS, and British Gas Corporation (BGC)/Lurgi processes. As individual components, each of these gasifiers has been determined by EPRI to be a commercially proven process. Thus, these could be considered for use in an IGCC system. The C- 23 only large-scale operating coal gasifier in the U.S. is at the Great Plains coal gasification project (Beulah, North Dakota) where 14 Lurgi gasifiers produce 137 million standard cubic feet per day of high-Btu gas from 14,2000 short tons of lignite. The Clean Energy project, sponsored by Foster Wheeler Power Systems was selected under CCT- I to demonstrate the technical, environmental, and economic performance of an IGCC power system for coproduction of power (44MW) and steam (200,000 Ibs/hour). This IGCC power plant will be designed to convert high-sulfur coal into electric power and steam in an environmentally acceptable manner, while offering a significant reduction in capital and operating costs over conventional coal-based technologies with flue gas cleaning. Currently, the project is in Phase 1 (design and permitting). Construction is scheduled for completion in 1990. Under the CCT-II Program, DOE has selected Combustion Engineering’s IGCC project encompassing pressurized, air blown, entrained-flow technology for commercial demonstration. The syngas will be cleaned of sulfur and particulates and then combusted in a gas turbine (40MW from which heat will be recovered in a heat recovery steam generator (HRSG). Steam from the gasification process and the HRSG will be used to power an existing steam turbine (25MW). Sulfur and NO, reductions of over 99 percent and over 80 percent, respectively, have been estimated. 11.0 Underground Coal Gasification Underground Coal Gasification (UCG) is the process by which coal is burned underground (in situ), and the heat generated by the oxidation pyrolytically decomposes and gasifies additional coal to produce combustible gas. As the coal is consumed, a cavity develops in the coal seam. The combustible synthesis gases are collected as product gases. Oxygen injection produces medium-Btu gas (at least 250 Btu/scf) that can be upgraded to synthetic natural gas and other products. Air injection produces low-Btu gas (approximately 125 Btu/scf) that is usually used onsite as a furnace fuel because it is costly to transport or upgrade it. Oxygen-enriched air may be used for power generation using combined cycle processes. Steam is necessary to control the gasification reactions and to act as a heat transfer agent. The most straightforward type of UCG process requires drilling one well to inject oxygen- containing gases and another to remove the gaseous products. Several linking techniques have been used to increase effective gas flow rates. The two most practical are reverse combustion and directional drilling. In reverse combustion, the coal is ignited at the bottom of the production well while air is forced into the injection well. The burn front is drawn by burning through fractures toward the source of oxygen charring a narrow channel counter-current to the flow of air. In directional drilling, a curved borehole is created from the surface to the coal seam which Tuns horizontally to intersect the vertical wells, providing the desired linkage. From an environmental standpoint, air quality degradation is not unique to UCG technology. Product gas cleanup is nearly identical to that used in surface gasification, but other areas of C-24 concem include groundwater contamination and gasification area subsidence. Both these concems are preventable to a great extent through proper site evaluation and selection procedures. Status of Technology UCG has progressed from a concept in 1972 to a highly promising technology. Since 1973, the federal government has sponsored 13 UCG tests on western subbituminous coal (7 at Hanna, Wyoming; 3 at Hoe Creek, Wyoming; 2 at North Knobs, Wyoming; and 1 at Centralia, Washington) and 1 UCG test on eastern bituminous coal at Pricetown, West Virginia. The tests demonstrated the technical feasibility of UCG and produced most of the data industry needs for a proof-of-concept test for shrinking subbituminous coals. A considerable amount of coal (2,000- 16,000 tons) has been gasified per test and operations have been run continuously for up to 102 days at coal consumption rates of 30-200 tons per day. Although UCG technology as proved feasible for western coals, significant research needs to be done before the technology will be feasible for application to eastern swelling coals. Under the CCT-I Program, Energy International was selected to demonstrate the cost effectiveness, reliability, and environmental acceptability of UCG technology for steeply dipping subbituminous coal beds at a site near Rawlins, Wyoming. The specific objective of this 12- month long project is to conduct a commercial-scale demonstration of 500 to 1,000 tons of coal per day to produce 24-48 million standard cubic feet per day of product gas. At present, the project is in Phase 2 (construction and start up). . 12.0 Heat Engines Heat engines pertain to technologies that require coal-based fuels for combustion in coal-fired gas turbines and diesel engines. The gas turbine converts the energy of a hot gas stream to shaft horsepower which can be used to generate electricity, pump liquids or gases, or drive vehicular or marine propulsion systems. Normally, wasted heat released by the gas turbine can produce steam for direct use (cogeneration) or generate additional electricity through a steam cycle. The gas turbine has inherent advantages (compared to the steam turbine) in efficiency, size, capital cost, procurement time, operational flexibility, and system adaptability. The coal-fired gas turbine power systems are expected to meet present environmental emissions regulations for particulates, NO, and SO,. The coal burning gas turbine is an excellent choice for repowering applicants, however, for retrofitting or modernizing applications, provided that proper fuels are developed, an existing oil- or gas-fired turbine could be retrofitted to burn a highly beneficiated coal-water mixture. The diesel engine is a high-compression, sparkless internal combustion engine which typically burns premium fuel oil distillates or with suitable modification, heavier petroleum fuels of natural or medium Btu gas, or properly de-ashed liquids from coal or oil shale. The diesel offers major benefits in efficiency, load-following capability, compactness, and capital cost. Presently, there are no emission regulations pertaining to diesel engines. Since there is no opportunity to clean C-25 the working fluid within the engine, cleanup must be accomplished in the supplied fuel or in the engine exhaust, perhaps by using a combination of highly beneficiated fuel and exhaust cleanup devices. Status of Technology’ The direct firing of coal in gas turbines was attempted in the 1950’s and 1960's mainly in the U.S. and Australia. Inability to solve the serious erosion, corrosion, and ash deposition problems which were encountered, forced abandonment of these efforts. A current DOE program focuses on potentially lower cost coal-based fuel forms, i.e., minimally cleaned fuel gas and fine particulate coal in either dry powder or slurry form. In addition to clean coal-based fuels, the program is investigating post-combustion cleanup techniques which could allow the burning of a poorer quality fuel while still protecting the power turbine. Coal was first evaluated as fuel in diesel engines in Germany in the early 1940’s. Coal dust was tried in a_ slow speed engines but excessive cylinder wear discouraged continuation. The coal used in these early tests did not have the benefits of present day clean coal technologies. The current DOE program is based upon several of these advanced technologies, i.e., coal beneficiation, fine grinding, special fuels formulation, coal gasification, and hot gas cleaning. The coal-fired diesel work has progressed to preliminary test evaluation along with bench-scale research on combustion characteristics, fuel injection, and component wear. in sddition, laboratory bench tests have been conducted to establish fundamental data relevant to engine design features required to utilize these fuels. There are no projects in the CCT-I Program directly involving heat engine technology, however, the following two projects in the CCT-I Program relate to heat engines. While neither of these projects are intended specifically to demonstrate heat engines, the technology supports gas and/or steam turbine development. 1, The Appalachian IGCC Demonstration Project - Fluidized bed gasification with hot gas cleanup and integrated combined cycle (cosponsored jointly by M.W. Kellogg Company and Bechtel Development Company). 2. Clean Energy IGCC Demonstration Project - Integrated combined-cycle for coproduction of power and steam (cosponsored jointly by Consolidation Coal Company and Foster Wheeler Power Systems, Inc.). 13.0 Industrial Processes The industrial sector of the energy-consuming marketplace offers significant potential for the development of new approaches or technologies to use coal as a more efficient and environmentally responsive energy option. The clean coal demonstration technologies have wide application in industries such as iron, cement, paper, and acid manufacturing. C - 26 Control technologies similar to those used by utility and industrial boilers can be applied to industrial processes which generate SO,, NO,, and particulates and will achieve similar reductions in many cases. In the example above, the process, by eliminating the coking step, is environmentally superior to established ironmaking methods, and has the ability to operate on a wide range of coal and iron feedstocks. NO, emissions are often due to the high temperatures required by a particular process. In such cases, technologies such as low-NO, burners may not be applicable since NO, control is achieved by lowering combustion temperatures. Fluidized-bed combustion and advanced combustors have application in steam raising and cogeneration, and gasification in production of clean fuel or as a feedstock for the production of highly valued chemicals. Direct heating technologies are used in process heat applications in which the combustion products directly impinge on the manufactured product. For indirect heating applications, a tube wall prevents the combustion products from impinging on the manufactured product as in the case of fired heaters in petroleum refining. The limitation to coal use in direct and indirect heating includes product contamination, flame stabilization, and environmental intrusion. Status of Technology Two industrial processes were recently selected for commercial demonstration by DOE under the CCT-II Program: 1. Bethlehem Steel Corporation’s Coke Oven Gas Cleaning Project will demonstrate an innovative coke oven gas desulfurization system which can be retrofitted into existing coke oven gas handling facilities. The project will combine coke oven gas desulfurization and sulfur recovery with ammonia recovery and destruction. The ammonia indigenous in the gas stream will be utilized to remove the hydrogen sulfide from the stream. 2. The Passamaquoddy Tribe will demonstrate a retrofittable scrubbing system for removing SO, emissions form existing coal-burning cement kilns. This new technology reduces SO, emissions by over 90 percent, uses kiln waste dust as the scrubbing reagent, produces a recycle stream for feeding to the kiln and two potentially saleable by-products (potassium-based fertilizer and distilled water), and generates no new wastes. C- 27 APPENDIX D FEDERAL ENVIRONMENTAL REGULATORY REQUIREMENTS Appendix D FEDERAL ENVIRONMENTAL REGULATORY REQUIREMENTS The purpose of this appendix is to examine major federal environmental laws and regulations which may affect broad-scale commercialization of clean coal technologies. State and local laws are also influential but are not discussed here since the primary federal statues establish the basic framework within which the states must act. The Clean Coal Technology Demonstration Program is directed toward the Special Envoys’ recommendation on demonstrating technologies that can significantly reduce emissions of SO, and NO, pollutants commonly associated with acid rain from existing coal-burning facilities. To obtain near-term reductions in emissions that can help reduce acid precipitation affecting ecosystems in the United States and Canada, many of these projects involve retrofit technologies for pollution control or technologies for repowering exisitng facilities or for use in new facilities to generate electricity from coal more cleanly and efficiently. Thus, emphasis is given here to environmental regulations that affect electric power generation. Specifically, this section addresses the: . Clean Air Act and its amendments; . Clean Water Act and related actions protecting wetlands and floodplains; and . Resource Conservation and Recovery Act and its amendments. Clean Air Act Standards and regulations issued under the Clean Air Act and related legislation are the most critical to the commercialization of clean coal technologies. This Act administered jointly by the U.S. Environmental Protection Agency (EPA) and the states, is intended to ensure that air quality is maintained or improved. National Ambient Air Quality Standards (NAAQS) set by EPA are the foundation of the air quality program. New source performance standards (NSPS) emissions limitations applicable to specific categories of stationary facilities having the potential to emit more than a specified amount of pollutants per year are instrumental in achieving NAAQS. Regulatory approaches differ in areas where air quality is better than ambient standards for regulated pollutants and in areas where standards are not met. Where ambient air quality is better than national standards, Prevention of Significant Deterioration (PSD) permitting requirements apply. Where air quality measured for one or more regulated pollutants does not meet national standards, Nonattainment Areas New Source Review requirements must be met. D-1 National Ambient Air Quality Standards Since 1970, air pollution abatement efforts have focused on limiting emissions of SO,, NO,, CO, particulates, and organic compounds that promote ozone formation in the lower atmosphere. Lead was added to the list in 1978. For these substances, EPA has established NAAQS which set maximum allowable concentrations in the atmosphere according to type of effects they pose. Under NAAQS, both primary and secondary standards must be met. Primary standards set emissions levels above which concentrations of regulated pollutants are believed to threaten public health. Secondary standards set emissions levels for these pollutants above which public welfare is believed to be negatively affected (Table D-1). Effective July 31, 1987, the concentration limit and basis for measurement for particulate matter were changed. Previously based on the total suspended particulates (TSP), attainment of primary and secondary NAAQS for particulate matter now must be determined by measuring particles termed "PM,," (those with an aerodynamic diameter <10 um). The major reason for this change was to account for the grater potential health and welfare effects of smaller respirable particles. New Source Performance Standards Stationary sources, including electric generating plants and certain types of industrial equipment, must meet federal NSPS emissions limits (Table D-2). During the 1970s and 1980s, EPA promulgated several different "sets" of NSPS applicable to fossil-fuel steam generators. Generally, the date when construction, reconstruction, or modification begins and boiler capacity determine which NSPS a steam generating unit must meet. States may (and some have) set ambient and emission standards more stringent than federal standards. Regulatory Approaches Under the Clean Air Act Programs Under the Clean Air Act, areas of the country are designated as "Attainment" or "Nonattainment" for regulated pollutants. Attainment areas are those in which ambient air quality is better than national standards for an NSPS pollutant. Nonattainment areas are those in which air quality standards are exceeded for a regulated pollutant. One area may be attainment for some pollutants and nonattainmnet for others. Regulatory approaches applicable to attainment and nonattainmnet areas differ and may affect permitting and performance requirements of innovative clean coal technologies. In Attainment areas, the regulatory goal is to preserve the existing air quality. New sources must demonstrate that their development will not increase ambient concentrations of contaminants beyond established acceptable increments above assumed baselines. The increments must serve all new sources and total increments generally will not be available to a single facility. In such areas, new sources in any of 28 categories established by EPA (including fossil-fueled electric D-2 TABLE D-1 NAAQS for air pollutants. Pollutant/averaging period Primary standard Secondary standard (ug/m*) (ppm) _— (mg/m) (ppm) Sulfur dioxide Annual arithmetic mean 80 0.03 24-hour 365 0.14 3-hour 1,300 0.5 Particulate matter (as PM,p)" Annual arithmetic mean 50 Same 24-hour 150 Same Carbon monoxide 8-hour 10,000 9 Same 1-hour 40,000 35 Same Ozone 1-hour 235 0.12 Same Nitrogen dioxide Annual arithmetic mean 100 0.05 Same Lead Maximum quarterly 1.5 Same average *PM,y = particulate matter with an aerodynamic diameter <10 um. Table D-2 New Source Performance Standards Clean Air Act, Part 60. Affected Affected Subpart Date Size Pollutant Standard Db) Standard for Industrial After >29 MW, sO, 1.2 1b/10® Btu and 90% reduction Steam Generating Units 6/19/84 in potential concentration Particulate .05 1b/10* Btu NO, .05 to .08 Ib/10* Btu depending on coal & boiler type Db-60-42b) Standards for "Emerging" After sO, 0.6 Ib 10° Btu and 50% reduction SO, Control Technology 6/19/86 in potential emissions Db-60-42b) Standards for Fluidized SO, 1.2 1b/10° Btu and 80% reduction Bed Combustors (firing coal refuse); as above if firing coal. No percent reduction requirements for low capacity duct burners as part of combined cycle systems or factor facilities Da) Standards for Electric After >73 MW, = SO, 1.2 1b/10° Btu and 90% reduction Utility Steam Generating 9/18/78 in Units potential concentration Particulate .03 1b/10° Bru NO, .02 to .08 Ib/10* Btu - 25% to 65% reduction depending on coal and burner type D) Standards for Fossil Fuel- After >73 MW, ‘SO, 1.2 1b/10° Bru Fired Steam Generating 8/17/71 Units Particulate .03 1b/10° Bru NO, .05 to .08 Ib/10* Btu depending on coal and burner type D-4 generating facilities with a heat input capacity of more than 73 MW) with the potential to emit 100 tons/year or more of a NAAQS pollutant must undergo PSD New Source Review. For new sources not listed as one of the 28, the emission rate "trigger" for PSD review is 250 tons/year. These requirements also apply to major modifications to existing facilities which may result in a "significant" increase in any pollutant for which the area is attainment. The definition of a significant increase differs among criteria pollutants. In Nonattainment areas, the regulatory goal is to improve air quality to meet NAAQS. A major stationary source for these areas is one with potential to emit 100 tons/year or more without regard to source category. For Nonattainment areas, EPA has instituted an "offset policy." This policy requires of new sources: * lowest achievable emission rate; * compliance of applicant’s existing sources; * emissions offsets; and * net positive air quality benefit. Emission offsets (reductions) must be obtained from existing sources in an amount at least equal to the proposed new emissions. Emission offsets may be from facilities controlled by the applicant or from other outside sources. Only intra-pollutant emission tradeoffs are acceptable. For example, particulate matter reductions may not be used to offset new or increased SO, emissions. For net positive air quality benefit, it must be shown that emission offsets will provide a positive net air quality benefit in the Nonattainment area to ensure reasonable further progress toward attainment of the NAAQS. Clean Water Act The Clean Water Act is intended to ensure that the overall quality of navigable waters of the United States is either improved or maintained at levels that will support their highest use. (As with the Clean Air Act, this legislation also is based on federal-state cooperation.) Standards act as a "floor" below which water quality should not drop, and effluent discharge limits "at the end of the pipe" are intended to ensure that these standards are met. Title III of this Act directs EPA to set these discharge standards and gives the Agency enforcement powers. Title IV establishes a permit program system, the National Pollution Discharge Elimination System, that regulates discharges to surface waters. No person may discharge any regulated pollutant into any surface water without a permit issued by either the EPA or a state. EPA has not published specific effluent limitations for many source categories that may discharge to surface waters; but for certain types of facilities that are listed in this Act, such as steam electric power plants, EPA has established effluent limitations for existing and new sources. D-5 Resource Conservation and Recovery Act and Amendments The Resource Conservation and Recovery Act (RCRA) and the 1984 Hazardous and Solid Waste Amendments (HSWA) are intended to ensure that all "solid" waste, including suspensions, other liquids, and especially hazardous waste, is handled so as to minimize risks to the environment and the public. RCRA provides for "cradle to grave" tracking by requiring waste generators, transporters, and treatment/storage/disposal facilities to use a manifest system keyed to a generator identification number. Treatment/storage/disposal facilities must obtain permits which set facility-specific requirements for waste-handling methods. HSWA limits land disposal of many wastes and sets strict requirements for construction and operation of land disposal facilities. Currently, EPA does not consider coal combustion wastes (bottom ash, fly ash, etc.) to be hazardous. It is investigating whether such large-quantity wastes require any special disposal methods and whether they should be considered hazardous if they contain small quantities or other substances such as catalysts or filter cakes that may contain heavy metals or leachable organics. If catalysts, filter cakes, slag, ash, or byproducts contain sufficient amounts of heavy metals or extractable/leachable organics and are disposed of off site or without mixing with other solid wastes, they could be classified as hazardous. Westlands/Floodplains According to Executive Order 11900, "Protection of Wetlands," construction in wetlands should be avoided unless there are no practicable alternatives and all practicable measures have been included in the program to minimize harm to wetlands that might result from such use. Review of an action to construct in wetlands/floodplains is to be provided to the public. Executive Order 11988, "Floodplain Management," states that each federal agency must determine if any action will occur in a floodplain and, if so, the potential effects of that action must be evaluated. The agency is to consider alternatives to avoid adverse effects and incompatible development in floodplains. National Environmental Policy Act An overall strategy for compliance with the National Environmental Policy Act of 1969 has been developed for the Clean Coal Technology Demonstration Program, consistent with the Council on Environmental Quality (CEQ) NEPA regulations (40 CFR 1500-1508) and the DOE guidelines for compliance with NEPA (10 CFR 1021). This strategy includes the preparation of both programmatic and project-specific environmental impact analyses, prior to and subsequent to project selection. Programmatic Environmental Impact Statement DOE is preparing a Programmatic Environmental Impact Statement (PEIS) to be issued before the selections are made for the CCT-III solicitation. The direct action being considered in the PEIS is the selection, for cost-shared federal funding, of one or more projects to demonstrate Clean Coal Technologies. The indirect effect of this program is the expected wide spread commercialization by the private sector of successfully demonstrated Clean Coal Technologies. It is the potential environmental consequences of wide spread commercialization of these technologies in the year 2010 that will be addressed in the PEIS. Pre-Selection Project-Specific Environmental Review For proposals that undergo comprehensive evaluation, DOE will prepare pre-selection project specific environmental reviews which will focus on the environmental issues pertinent to decision making. Such reviews will summarize the strengths and weaknesses of each proposal against the environmental evaluation criteria including, to the maximum extent possible, a discussion of alternative sites and/or processes reasonably available to the proposer, a brief discussion of the environmental impacts of each proposal, necessary mitigative measures and, to the extent known, a list of permits and licenses which must be obtained in implementing the proposal. These confidential environmental reviews will be provided to the Source Selection Official for use in the selection process. In addition, DOE will document the consideration given to environmental factors in a publicly available selection statement to record that the relevant environmental consequences of reasonable alternatives have ben evaluated in the selection process. This selection statement will be filed with the Environmental Protection Agency, in accordance with the DOE NEPA guidelines. Post-Selection Site-Specific Review The third element of the NEPA strategy provides for DOE to prepare site-specific documentation for each project selected for financial assistance. Funds from the program will not be provided to the project for detailed design, construction, operation, and/or dismantlement until this element of the NEPA process has been successfully completed. D-7