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Clean Coal Technology Demonstration Program 2000
$v0-44/400 ~ wesboig uoesjsuoweg ABojouyse| |20D Ues|D Oz dy eC EN COAL TECHNOLOGY fe <ERT OF STOR, & e KS y, . {| }:) \h /S) SLE States 8 aT U.S. Department of Energy Assistant Secretary for Fossil Energy Washington, DC 20585 Clean Coal Technology Demonstration Program Program Update As of September 1999 April 2000 DOE/FE-0415 For further information about this publication or related U.S. DOE programs please contact: Victor K. Der David J. Beecy Dr. C. Lowell Miller Product Line Director Product Line Director Product Line Director Power Systems Environmental Systems Fuels & Industrial Systems U.S. Department of Energy US. Department of Energy U.S. Department of Energy Mail Stop FE-22 GTN Mail Stop FE-23 GIN Mail Stop FE-24 GTN 19901 Germantown Road 19901 Germantown Road 19901 Germantown Road Germantown, MD 20874-1290 Germantown, MD 20874-1290 Germantown, MD 20874-1290 (301)903-2700 (301) 903-2787 (301) 903-9453 Comments, corrections, or contributive information may be directed to: Program Update and Program Fact Sheets c/o Gene H. Kight Sr. Financial & Procurement Director U.S. Department of Energy Mail Stop FE-20 GTN 19901 Germantown Road Germantown, MD 20874-1290 (301)903-2624 (301)903-9301 (fax) gene.kight@hq.doe.gov This report has been reproduced directly from the best available copy. Available to DOE and DOE contractors from the Office of Scientific and Technical Information, P.O. Box 62, Oak Ridge, TN 37831; prices available from (615) 576-8401. Available to the public from the National Technical Information Service, U.S. Department of Commerce, 5285 Port Royal Rd., Springfield, VA 22161. &® Printed with soy ink on recycled paper DOE/FE-0415 ___ COAL Clean Coal Technology TECHNOLOGY| Demonstration Program Program Update As of September 1999 U.S. Department of Energy i Assistant Secretary for Fossil Energy April 2000 Washington, DC 20585 b | Not ! Executive Summary 0 Section 1: Role of the CCT Program 0 | Section 2: Program Implementation 0 Section 3: Funding and Costs 0 5 Section 4: CCT Program Accomplishments 0 | % Section 5: CCT Projects 0 EB Appendix A: Historical Perspective and Legislative History 0 Appendix B: Program History 0 Appendix C: Environmental Aspects 0 | Appendix D: CCT Project Contacts 0 | Appendix E: Acronyms, Abbreviations, and Symbols 0 Program Update Evaluation Not Used Effective 1 | 1 1 What do you find is the best and most effective part of the Program Update? Very Effective 4 5 4 5 4 5 4 5 4 5 4 5 4 5 4 5 4 5 4 5 4 5 In an effort to continue providing the most useful and effective information to the users of the Program Update, the U.S. Department of Energy (DOE) is including the following evaluation form. Please take a few minutes to complete the evaluation and mail your comments to DOE. The results will be | used to improve the next edition of this document—Program Update 2000. | On a scale of | to 5, with 1 meaning not effective and 5 meaning very effective, please rate each of the chapters by circling the appropriate number. A space has been provided to make comments. If you do not use a particular chapter and cannot comment on its effectiveness, please circle zero. Comments? hI What do you find is the least effective part of the Program Update? Do you have any other suggestions on how to improve the Program Update? If you picked up this Program Update and are not on the mailing list and would like to be added, please tape your business card below or neatly print your name and address. Name: Address: Address: City: State or Province: Country: ZIP or Postal Code: Phone Number: Fold Here Fold Here — First | | Class | | Postage | Required Program Update Evaluation c/o Technology & Management Services, Inc. 18757 North Frederick Road Gaithersburg, Maryland 20879 Tape Here, Do Not Staple Contents Executive Summary: The CCT Program Update 1999 Section 1: Role of the CCT Program Section 2: Program Implementation Introduction ES-/ Role of the CCT Program ES-2 Program Implementation ES-4 Funding and Costs ES-5 CCT Program Accomplishments ES-6 CCT Projects ES-20 Introduction /-/ Coal Technologies Respond to Need /-/ Coal Technologies for Environmental Performance /-3 SO, Regulation /-3 NO, Regulation 1-4 Particulate Regulation /-6 Hazardous Air Pollutants /-7 Global Climate Change /-7 Regional Haze /-8 Solid Waste /-8 Toxics Release Inventory /-8 Coal Technologies for Competitive Performance /-8 Coal Technologies to Sustain Economic Growth /-10 Coal Technology for the Future /-// Introduction 2-/ Implementation Principles 2-/ Implementation Process 2-2 Commitment to Commercial Realization 2-4 Solicitation Results 2-6 Future Implementation Direction 2-/3 Program Update 1999 i Section 3: Funding and Costs Section 4: CCT Program Accomplishments Section 5: CCT Projects ii Program Update 1999 Introduction 3-/ Program Funding 3-2 General Provisions 3-2 Availability of Funding 3-2 Use of Appropriated Funds 3-4 Project Funding, Costs, and Schedules 3-4 Cost-Sharing 3-8 Recovery of Government Outlays (Recoupment) 3-8 Introduction 4-/ Marketplace Commitment 4-2 Environmental Control Devices 4-2 Advanced Electric Power Generation 4-6 Coal Processing for Clean Fuels 4-9 Industrial Applications 4-// Awards 4-// Market Communications—Outreach 4-// Information Sources 4-/4 Publications Issued in FY1999 4-/4 Information Access 4-/5 Information Dissemination and Feedback 4-/6 Seventh Clean Coal Technology Conference 4-/6 Conferences and Workshops Held in FY1999 4-20 Trade Mission Activities in FY1999 4-24 Introduction 5-/ Technology Overview 5-2 Environmental Control Devices 5-2 Advanced Electric Power Generation Technology 5-7 Coal Processing for Clean Fuels Technology 5-/0 Industrial Applications Technology 5-/0 Section 5: CCT Projects (continued) Appendix A: Historical Perspective and Legislative History Appendix B: Program History Appendix C: Environmental Aspects Project Fact Sheets 5-/2 Environmental Control Devices 5-/9 SO, Control Technologies 5-/9 NO, Control Technologies 5-4/ Combined SO,/NO, Control Technologies 5-71 Advanced Electric Power Generation 5-99 Fluidized-Bed Combustion 5-99 Integrated Gasification Combined-Cycle 5-/15 Advanced Combustion/Heat Engines 5-/25 Coal Processing for Clean Fuels 5-/3/ Industrial Applications 5-/47 Historical Perspective A-/ Legislative History A-2 Solicitation History B-/ Selection and Negotiation History B-/ Introduction C-/ The Role of NEPA in the CCT Program C-2 Compliance with NEPA C-2 Categorical Exclusions C-2 Memoranda-to-File C-2 Environmental Assessments C-2 Environmental Impact Statements C-5 NEPA Actions in Progress C-5 Environmental Monitoring C-6 Air Toxics C-6 Program Update 1999 iii Appendix D: CCT Project Contacts Appendix E: Acronyms, Abbreviations, and Symbols Index of CCT Projects and Participants iv Program Update 1999 Project Contacts D-/ Environmental Control Devices D-/ Advanced Electric Power Generation D-4 Coal Processing for Clean Fuels D-6 Industrial Applications D-7 Acronyms, Abbreviations, and Symbols E-/ State Abbreviations E-4 Index J/ndex-1 Exhibits Executive Summary: The CCT Program Completed Projects by Application Category ES-6 upc Summary of Results of Completed Environmental Control Technology Projects ES-7 Commercial Successes—Environmental Control Technologies ES-// Summary of Results of Completed Advanced Electric Power Generation Projects ES-/5 Commercial Successes—Advanced Electric Power Generation Technologies ES-/6 Summary of Results of Completed Coal Processing for Clean Fuels Projects ES-/7 Commercial Successes—Coal Processing for Clean Fuels Technologies ES-/8 Summary of Results of Completed Industrial Application Projects ES-/9 Commercial Successes—Industrial Application Technologies ES-/9 Project by Application Category ES-22 Award-Winning CCT Projects ES-24 Section 1: Role of the CCT Program Phase I SO, Compliance Methods /-3 CAAA NO, Emission Limits /-4 Comparison of Energy Projections for Electric Generators /-9 Vision 21 Objectives /-// Section 2: Program Implementation CCT Program Selection Process Summary 2-6 Clean Coal Technology Demonstration Projects by Solicitation 2-7 Geographic Locations of CCT Projects—Environmental Control Devices 2-9 Geographic Locations of CCT Projects—Advanced Electric Power Generation 2-/0 Geographic Locations of CCT Projects—Coal Processing for Clean Fuels 2-// Geographic Locations of CCT Projects—Industrial Applications 2-/2 Section 3: Funding and Costs CCT Project Costs and Cost-Sharing 3-/ Relationship between Appropriations and Subprogram Budgets for the CCT Program 3-2 Annual CCT Program Funding by Appropriations and Subprogram Budgets 3-3 CCT Financial Projections as of September 30, 1999 3-4 Program Update 1999 v Section 3: Funding and Costs (continued) Financial Status of the CCT Program as of September 30, 1999 3-5 CCT Project Schedules and Funding, by Application Category 3-6 Section 4: CCT Program Accomplishments Commercial Successes—SO, Control Technology 4-4 Commercial Successes—NO, Control Technology 4-5 Commercial Successes—Combined SO,/NO, Control Technology 4-7 Commercial Successes—Advanced Electric Power Generation 4-/0 Commercial Successes—Coal Processing for Clean Fuels 4-/2 Commercial Successes—Industrial Applications 4-/2 Award-Winning CCT Projects 4-/3 How to Obtain Updated CCT Program Information 4-15 Section 5: CCT Projects CCT Program SO, Control Technology Characteristics 5-3 Group | and 2 Boiler Statistics and Phase IT NO, Emission Limits 5-4 CCT Program NO, Control Technology Characteristics 5-5 CCT Program Combined SO,/NO, Control Technology Characteristics 5-6 CCT Program Advanced Electric Power Generation Technology Characteristics 5-9 CCT Program Coal Processing for Clean Fuels Technology Characteristics 5-// CCT Program Industrial Applications Technology Characteristics 5-/3 Key to Milestone Charts in Fact Sheets 5-/4 Project Fact Sheets by Application Category 5-/5 Project Fact Sheets by Participant 5-/7 Variables and Levels Used in GSA Factorial Testing 5-22 GSA Factorial Testing Results 5-22 SO, Removal Performance 5-34 Estimated Costs for an AFGD System 5-35 Flue Gas Desulfurization Economics 5-35 Operation of CT-121 Scrubber 5-38 SO, Removal Efficiency 5-38 Particulate Capture Performance 5-39 vi Program Update 1999 Section 5: CCT Projects (continued) Appendix A: Historical Perspective and Relevant Legislation CT-121 Air Toxics Removal 5-39 LOI Performance Test Results 5-44 NO, vs. LOI Tests—All Sensitivities 5-44 Typical Trade-Offs in Boiler Optimization 5-44 Major Elements of GNOCIS 5-45 Coal Reburn Test Results 5-48 Coal Reburn Economics 5-49 NO, Data from Cherokee Station, Unit No. 3 5-56 Parametric Testing Results 5-6/ Catalysts Tested 5-64 Average SO, Oxidation Rate 5-64 Design Criteria 5-65 LNCFS™ Configurations 5-68 Concentric Firing Concept 5-68 Unit Performance Impacts Based on Long-Term Testing 5-69 Average Annual NO, Emissions and Percent Reduction 5-69 LIMB SO, Removal Efficiencies 5-88 Capital Cost Comparison 5-89 Annual Levelized Cost Comparison 5-89 Effect of Limestone Grind 5-92 Pressure Drop vs. Countercurrent Headers 5-92 Effect of Bed Temperature on Ca/S Requirement 5-//2 Calcium Requirements and Sulfur Retentions for Various Fuels 5-/13 ENCOAL Production 5-/44 BFGCI Test Results 5-/55 Summary of Emissions and Removal Efficiencies 5-/62 CCT Program Legislative History 4-4 Program Update 1999 vii Appendix C: Environmental Aspects NEPA Reviews Completed through September 30, 1999 C-/ Memoranda-to-File Completed C-3 Environmental Assessments Completed C-4 Environmental Impact Statements Completed C-5 NEPA Reviews in Progress C-5 Status of Environmental Monitoring Plans for CCT Projects C-7 CCT Projects Monitoring Hazardous Air Pollutants C-9 viii Program Update 1999 Project Fact Sheets by Application Category | Prte Participant Environmental Control Devices SO, Control Technologies 10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. Confined Zone Dispersion Flue Gas Desulfurization Demonstration LIFAC Sorbent Injection Desulfurization Demonstration Project Advanced Flue Gas Desulfurization Demonstration Project Demonstration of Innovative Applications of Technology for the CT-121 FGD Process NO, Control Technologies Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Demonstration of Coal Reburning for Cyclone Boiler NO, Control Full-Scale Demonstration of Low-NO, Cell Burner Retrofit Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler Micronized Coal Reburning Demonstration for NO, Control Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers Combined SO,/NO, Control Technologies Commercial Demonstration of the NOXSO SO,/NO, Removal Flue Gas Cleanup System SNOX™ Flue Gas Cleaning Demonstration Project SO,-NO,-Rox Box™ Flue Gas Cleanup Demonstration Project Enhancing the Use of Coals by Gas Reburning and Sorbent Injection LIMB Demonstration Project Extension and Coolside Demonstration Milliken Clean Coal Technology Demonstration Project Integrated Dry NO./SO, Emissions Control System Advanced Electric Power Generation Fluidized-Bed Combustion McIntosh Unit 4A PCFB Demonstration Project McIntosh Unit 4B Topped PCFB Demonstration Project | JEA Large-Scale CFB Combustion Demonstration Project Bechtel Corporation LIFAC-North America Pure Air on the Lake, L.P. Southern Company Services, Inc. Southern Company Services, Inc. The Babcock & Wilcox Company The Babcock & Wilcox Company Energy and Environmental Research Corporation New York State Electric & Gas Corporation Southern Company Services, Inc. Southern Company Services, Inc. NOXSO Corporation ABB Environmental Systems The Babcock & Wilcox Company Energy and Environmental Research Corporation McDermott Technology, Inc. New York State Electric & Gas Corporation Public Service Company of Colorado City of Lakeland, Lakeland Electric City of Lakeland, Lakeland Electric JEA 5-20 5-24 5-28 5-32 5-36 5-42 5-46 5-50 5-54 5-58 5-62 5-66 5-72 5-74 5-78 5-82 5-86 5-90 5-94 5-100 5-102 5-104 Program Update 1999 ix x Project Tidd PFBC Demonstration Project Nucla CFB Demonstration Project Integrated Gasification Combined-Cycle Kentucky Pioneer IGCC Demonstration Project Pifion Pine IGCC Power Project Tampa Electric Integrated Gasification Combined-Cycle Project Wabash River Coal Gasification Repowering Project Advanced Combustion/Heat Engines Healy Clean Coal Project Clean Coal Diesel Demonstration Project Coal Processing for Clean Fuels Commercial-Scale Demonstration of the Liquid Phase Methanol (LPEMEOH™) Process Self-Scrubbing Coal™: An Integrated Approach to Clean Air Advanced Coal Conversion Process Demonstration Development of the Coal Quality Expert™ ENCOAL* Mild Coal Gasification Project Industrial Applications Clean Power from Integrated Coal/Ore Reduction (CPICOR™) Pulse Combustor Design Qualification Test Blast Furnace Granular-Coal Injection System Demonstration Project Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Cement Kiln Flue Gas Recovery Scrubber Program Update 1999 Participant The Ohio Power Company Tri-State Generation and Transmission Association, Inc. Kentucky Pioneer Energy, L.L.C. Sierra Pacific Power Company Tampa Electric Company Wabash River Coal Gasification Repowering Project Joint Venture Alaska Industrial Development and Export Authority Arthur D. Little, Inc. Air Products Liquid Phase Conversion Company, L.P Custom Coals International Western SynCoal L.L.P ABB Combustion Engineering, Inc., and CQ Inc. ENCOAL Corporation CPICOR™ Management Company, L.L.C. ThermoChem, Inc. Bethlehem Steel Corporation Coal Tech Corporation Passamaquoddy Tribe Page 5-106 5-110 5-116 5-118 5-120 5-122 5-126 5-128 5-132 5-134 5-136 5-138 5-142 5-148 5-150 5-152 5-156 5-160 Project Fact Sheets by Participant Participant Project Page ABB Combustion Engineering, Inc., and CQ Inc. Development of the Coal Quality Expert™ 5-138 ABB Environmental Systems SNOX™ Flue Gas Cleaning Demonstration Project 5-74 Air Products Liquid Phase Conversion Company, L.P. Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOH™) Process 5-132 AirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption 5-20 Alaska Industrial Development and Export Authority Healy Clean Coal Project 5-126 Arthur D. Little, Inc. Clean Coal Diesel Demonstration Project 5-128 Babcock & Wilcox Company, The Demonstration of Coal Reburning for Cyclone Boiler NO, Control 5-46 Babcock & Wilcox Company, The Full-Scale Demonstration of Low-NO, Cell Burner Retrofit 5-50 Babcock & Wilcox Company, The SO, -NO, -Rox Box™ Flue Gas Cleanup Demonstration Project 5-78 Bechtel Corporation Confined Zone Dispersion Flue Gas Desulfurization Demonstration 5-24 Bethlehem Steel Corporation Blast Furnace Granular-Coal Injection System Demonstration Project 5-152 Coal Tech Corporation Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control 5-156 CPICOR™ Management Company, L.L.C. Clean Power from Integrated Coal/Ore Reduction (CPICOR™) 5-148 CQ Inc. (see ABB Combustion Engineering and CQ Inc.) Custom Coals International Self-Scrubbing Coal™: An Integrated Approach to Clean Air 5-134 ENCOAL Corporation ENCOAL® Mild Coal Gasification Project 5-142 Energy and Environmental Research Corporation Enhancing the Use of Coals by Gas Reburning and Sorbent Injection 5-82 Energy and Environmental Research Corporation Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler 5-54 JEA JEA Large-Scale CFB Combustion Demonstration Project 5-104 Kentucky Pioneer Energy, L.L.C. Kentucky Pioneer IGCC Demonstration Project 5-116 Lakeland, City of, Lakeland Electric McIntosh Unit 4A PCFB Demonstration Project 5-100 Lakeland, City of, Lakeland Electric McIntosh Unit 4B Topped PCFB Demonstration Project 5-102 LIFAC-North America LIFAC Sorbent Injection Desulfurization Demonstration Project 5-28 McDermott Technology, Inc. LIMB Demonstration Project Extension and Coolside Demonstration 5-86 New York State Electric & Gas Corporation Micronized Coal Reburning Demonstration for NO, Control 5-58 Program Update 1999 xi Participant Project Page L xii New York State Electric & Gas Corporation NOXSO Corporation Ohio Power Company, The Passamaquoddy Tribe Public Service Company of Colorado Pure Air on the Lake, L.P. Sierra Pacific Power Company Southern Company Services, Inc. Southern Company Services, Inc. Southern Company Services, Inc. Southern Company Services, Inc. Tampa Electric Company ThermoChem, Inc. Tri-State Generation and Transmission Association, Inc. Wabash River Coal Gasification Repowering Project Joint Venture Western SynCoal LLP Program Update 1999 Milliken Clean Coal Technology Demonstration Project Commercial Demonstration of the NOXSO SO,/NO, Removal Flue Gas Cleanup System Tidd PFBC Demonstration Project Cement Kiln Flue Gas Recovery Scrubber Integrated Dry NO,/SO, Emissions Control System Advanced Flue Gas Desulfurization Demonstration Project Pifion Pine IGCC Power Project Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Demonstration of Innovative Applications of Technology for the CT-121 FGD Process Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers Tampa Electric Integrated Gasification Combined-Cycle Project Pulse Combustor Design Qualification Test Nucla CFB Demonstration Project Wabash River Coal Gasification Repowering Project Advanced Coal Conversion Process Demonstration 5-90 5-72 5-106 5-160 5-94 5-32 5-118 5-42 5-36 5-62 5-66 5-120 5-150 5-110 5-122 5-136 Executive Summary: CCT Program Update 1999 Introduction CCT Program. The Clean Coal Technology Demonstration Program (CCT Program), a model of government and industry cooperation, advances the Department of Energy’s (DOE) mission to foster a secure and reliable energy system that is environmen- tally and economically sustainable. With 24 of the 40 active projects having completed operations, the CCT Program has yielded clean coal technologies (CCTs) that are capable of meeting existing and emerging environmental regulations and competing in a deregu- lated electric power marketplace. The CCT Program is providing a portfolio of technologies that will assure that the U.S. recoverable coal reserves of 274 billion tons can continue to supply the nation’s energy needs economically and in an environmentally sound manner. As the 20" century comes to a close, many of the clean coal technologies have realized commercial application. Industry now stands ready to respond to the energy and environmen- tal demands of the 21 century, both domestically and internationally. For existing power plants, there are cost-effective environmental control devices to control sulfur dioxide (SO,), nitrogen oxides (NO, ), and partic- ulate matter (PM). Also ready are a new generation of technologies that can produce electricity and other commodities, such as steam and synthetic gas, and provide the efficiencies and environmental performance responsive to global climate change. The CCT Pro- gram took a pollution prevention approach as well, demonstrating technologies that produce clean coal- based solid and liquid fuels by removing pollutants or their precursors before being burned. Lastly, new technologies were introduced into the major coal-using industries to enhance environmental performance. Thanks in part to the CCT Program, coal—abundant, secure, and economical—can continue in its role as a key component in the U.S. and world energy markets. Fiscal Year 1999 Major Accomplishments. The major accomplishments of the CCT Program during fiscal year 1999 are fivefold. First, low-NO, burner (LNB) technologies, integrated gasification combined- cycle (IGCC), and pressurized fluidized-bed combus- tion (PFBC) has established a strong foothold in the power generation market. Commercialization of LNBs continued, resulting in nearly half of the U.S. coal-fired boilers being retrofitted with LNBs. The Texaco gasification pro- cess that is being demonstrated in the Tampa Electric Integrated Gasification Combined-Cycle Project began to see market penetration with the Texaco technology being used in nearly half of 21 new IGCC projects. Additionally, the ABB Carbon PFBC technology demonstrated in the Tidd PFBC Demonstration Project is seeing commercial replication at 70-MWe and 360- MWe scale in Germany and Japan, respectively. Second, the Kentucky Pioneer Energy IGCC Demonstration Project has begun. The Kentucky- based project will help resolve a solid waste manage- ment problem and evaluate integration of gasification and fuel cell technologies. The project will use the BGL gasification technology in both an IGCC mode and coupled with a molten carbonate fuel cell (MCFC). Municipal solid waste will be collected and combined VY Tidd PFBC Demonstration Project (The Ohio Power Company)—1991 Powerplant Award presented by Power magazine. A Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company)—1997 Powerplant Award presented by Power magazine. Program Update 1999 ES-1 with coal to form fuel briquettes for the gasification process. The synthesis gas derived through gasifica- tion will fuel the MCFC. The nominal 400-MWe plant is scheduled to begin operations in 2003. Third, the Blast Furnace Granular-Coal Injection (BFGCI) System Demonstration Project operations were completed in September 1999. The project successfully demonstrated displacement of coke with coal and elimination of the pollutant emissions associ- ated with the production of the displaced coke. The technology demonstrated a $34 million savings in operating costs for Bethlehem Steel Corporation over the test period. The success resulted in commercial sale and installation at a U.S. Steel Corporation facility. Fourth, the DOE cost-shared operation for the Healy Clean Coal Project was completed in November 1999; however, data collection continues at no cost to DOE. Preliminary results show that the TRW slagging combustor and attendant cleanup system at Healy kept oxides of nitrogen (NO. ), sulfur dioxide (SO,), and particulate matter (PM) emissions well below the permit limits. Data collection will continue until 2001. Fifth and final, operations were successfully completed in 1999 for the Micronized Coal Reburning Demonstration for NO, Control project. The technolo- gy demonstrated in the project gives industry another tool to reduce NO, emissions. The results met or exceeded targeted NO, emissions reductions at the Milliken Station tangentially-fired boiler and Kodak Park cyclone boiler sites using a very low (14 percent) reburn fuel input. These accomplishments and more are described in further detail in this Clean Coal Technology Demon- stration Program: Program Update 1999. Final reports have been issued for several projects, providing details for industry to use in evaluating clean coal technologies. Numerous publications and periodicals ES-2_ Program Update 1999 have been produced to keep stakeholders informed of CCT Program progress. Conferences and trade mis- sions have been attended in order to promote these technologies. In sum, the CCT Program continuing to serve as a role model for successful government/ industry partnerships. Subsequent to the end of fiscal year 1999, but prior to publication of this report, the cooperative agreement for two demonstration projects expired—NOXSO Corporation and Custom Coals International are in bankruptcy and were not able to restructure and contin- ue work under the CCT Program. Information on NOXSO Corporation’s Commercial Demonstration of the NOXSO SO,/NO, Removal Flue Gas Cleanup System and Custom Coals International’s Self-Scrub- bing Coal™: An Integrated Approach projects are includ- ed in this report because there is data that readers may find beneficial. Furthermore, this report is based on the status as of September 30, 1999 and the expiration of these cooperative agreements occurred after that date. These two projects will not be included in future reports. Y Demonstration of Innovative Applications of Technology for the CT-121 FGD Process Project (Southern Company Services, Inc.)—1994 Powerplant Award presented by Power magazine. Role of the CCT Program Coal Technologies Respond to Need. Coal accounts for over 94 percent of the proven fossil energy reserves in the United States and supplies the bulk of the low-cost, reliable electricity vital to the nation’s economy and global competitiveness. In 1996, over half of the nation’s electricity was produced with coal, and projections by the Energy Information Agency (EIA) predict that coal will continue to domi- nate electric power production well into the first quarter of the 21° century. However, there is a need to use U.S. coal resources in an environmentally responsi- ble manner. The CCT Program was established to demonstrate the commercial feasibility of CCTs to respond to a growing demand for a new generation of advanced coal-based technologies characterized by enhanced operational, economic, and environmental perfor- mance. The first solicitation (CCT-I) for clean coal projects resulted in a broad range of projects being selected in four major product markets—environmental control devices, advanced electric power generation, coal processing for clean fuels, and industrial applications. The second round of solicitations (CCT-II) be- came the centerpiece for satisfying the recommenda- tions contained in the Joint Report of the Special Envoys on Acid Rain (1986). The goal was to demon- strate technologies that could achieve significant reductions in the emissions of precursors of acid rain, namely SO, and NO... The third round of solicitations (CCT-III) furthered the goal of CCT-II and added technologies that could produce clean fuel from run-of- mine coal. The fourth and fifth solicitations (CCT-IV and CCT-YV, respectively) recognized emerging energy and environmental issues, such as global climate change and capping SO, emissions, and thus focused on technologies that were capable of addressing these issues. CCT-IV called for energy efficient, economi- cally competitive technologies capable of retrofitting, repowering, or replacing existing facilities, while at the same time significantly reducing SO, and NO, emis- sions. CCT-V focused on technologies applicable to new or existing facilities that could significantly im- prove efficiency and environmental performance. Coal Technologies for Environmental Perfor- mance. Even before enactment of the Clean Air Act Amendments of 1990 (CAAA), the CCT Program was cognizant of the changes in electric power generation that would likely be caused by the statute. Several projects in the CCT Program were implemented at units designated as Phase I units in Title IV of the CAAA, which were required to meet SO, reductions by January 1, 1995. The CCT Program projects at Phase | units successfully reduced SO, emissions using ad- vanced flue gas desulfurization (AFGD) and repower- ing with integrated gasification combined-cycle. With the January 1, 2000, Phase II Title 1V CAAA provi- sions now upon us, the CCT Program’s portfolio of technologies will help industry meet the more stringent SO, emission limits. Unit operators now have several options for meeting SO, emission limits or exceeding them to generate SO, credits that can be sold in the emissions credit market. Furthermore, these SO, reduction technologies may be important in meeting new requirements for PM, , (particulate matter 2.5 microns and smaller in diameter) because some sulfur species are in this size range. In addition to SO, reductions, Title IV also called for reductions in NO, emissions. Phase I of the NO, provisions of Title IV requires reductions from the so- called Group | boilers—tangentially-fired and dry- bottom wall-fired boilers. The U.S. Environmental Protection Agency (EPA) used data developed during the CCT Program in establishing the NO, emission standards. Under Phase II, EPA established NO, emission limitations for Group 2 boilers and reduced the emission limits for Group | boilers. Group 2 boilers include cell-burner, cyclone, wet-bottom wall- fired, and vertically-fired boilers. The CCT Program has demonstrated NO, emission control techniques that are applicable to all of these boiler types. Furthermore, these technologies are not only applicable to Phase I and IT NO. emission reductions, but can be used in ozone nonattainment areas to make deeper cuts in NO, emissions, which are a precursor to ozone. Although the deadline has been stayed pending appeal, the EPA has issued a “SIP Call” to 22 states and the District of Columbia to take action to reduce regional transport of pollutants that contribute to ozone nonattainment in the Northeast. The SIP Call requires the 23 affected jurisdictions to revise their state imple- mentation plans (SIP) to reduce NO, emissions 85 percent below 1990 rates or achieve a 0.15 Ib/10° Btu emission rate by May 2003. In addition, EPA has tightened the New Source Performance Standard (NSPS) for electric and industrial boilers built or modified after July 9, 1997. The CCT Program has demonstrated several advanced electric power genera- tion technologies that can be used to meet the new requirements or exceed the requirements to produce NO, credits that could be sold to unit operators unable to meet the requirements. Furthermore, an environ- mental controls database has been developed that A Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.}—1993 Powerplant Award presented by Power magazine. provides a foundation for evaluating technologies to meet the increasingly stringent standards for existing units. Air toxics is another important area of environ- mental concern addressed by the CCT Program. Under Title I of the CAAA, EPA is responsible for determin- ing the hazards to public health posed by 189 identified hazardous air pollutants (HAPs). The CCT Program made a significant contribution to a better understand- ing of potential HAPs from power plant emissions by monitoring HAPs from CCT Program project sites. The results of these and other studies have significantly mitigated concerns about HAP emissions from coal- fired power plants and focused attention on mercury emissions, The CCT Program is also cognizant of concerns about global climate change. Clean coal technologies (such as IGCC) being demonstrated in the CCT Pro- gram offer utilities an option to reduce greenhouse gases (GHG) by as much as 25 percent with first generation systems through enhanced efficiency. Commercialization of atmospheric fluidized-bed Program Update 1999 ES-3 combustion (AFBC) and pressurized fluidized-bed combustion will also serve to reduce GHGs. Coal Technologies for Competitive Perfor- mance. As the electric generation market moves from a regulated industry to a free market, the CCT Program has kept pace with the changes. Whether the changes are brought about by the federal government through existing or new legislation or by state governments, the CCT Program is demonstrating the first generation of many technologies that will be needed in a competitive power generation market. These new technologies will be far more efficient than existing plants and environ- mentally benign. Coal Technologies to Sustain Economic Growth. It is in the nation’s interest to maintain a diverse energy mix to sustain domestic economic growth. The CCT Program is contributing to this interest by developing and deploying a technology portfolio that enhances the efficient use of the United States’ abundant coal resource while simultaneously achieving important environmental goals. The ad- vancements in coal use technology resulting from the CCT Program will reduce dependence on foreign energy resources and create an international market for these new technologies. The worldwide market for power generation technologies could be as high as $80 billion between 1995 and 2020. Coal Technology for the Future. The invest- ment in the CCT Program is forming a solid foundation upon which to build a responsible future for fossil energy while addressing growing global and regional environmental concerns and providing low cost energy. The Department of Energy’s Office of Coal & Power Systems (OC&PS) has identified specific program areas to build upon the successes of the CCT Program and provide a solid foundation upon which to progress ES-4 Program Update 1999 toward Vision 21. Vision 21 is a long-term strategic concept which integrates OC&PS program goals to develop the full potential of the nation’s abundant fossil fuel resources while addressing regional and global environmental concerns. Vision 21 plants would comprise a portfolio of fuel-flexible systems and modules capable of producing a varied slate of high- value commodities, such as clean fuels, chemicals, and electricity, tailored to meet market demands in the 2010-2015 time frame. The OC&PS program areas, which include Central Power Systems, Distributed Generation, Fuels, co, Sequestration, and Advanced Research, were developed to align with and directly support the goals and objectives of the Comprehensive National Energy Strategy. The OC&PS program addresses key domestic and global environmental concerns, while being responsive to DOE strategies to enhance scientific understanding and promote secure, efficient, and comprehensive energy systems. Program Implementation Implementation Principles. There are 10 guiding principles that have been instrumental in the success of the CCT Program. These principles are: * Strong and stable financial commitment for the life of the project, including full funding of the government’s share of the costs; + Multiple solicitations spread over a number of years, enabling the CCT Program to address a broad range of national needs with a portfolio of evolving technologies; + Demonstrations conducted at commercial scale in actual user environments, allowing clear assessment of the technology’s commercial potential; + A technical agenda established by industry, not the government, enhancing commercialization potential; * Clearly defined roles of government and industry, reflecting the degree of cost-sharing required; + A requirement for at least 50 percent cost- sharing throughout all project phases, enhanc- ing participant’s commitment; + An allowance for cost growth, but with a ceiling and cost-sharing, recognizing demonstration risk and providing an important check-and- balance to the program; * Industry retention of real and intellectual property rights, enhancing commercialization potential; + A requirement for industry to commit to commercialize the technology, reflecting commercialization goals; and + A requirement for repayment up to the government’s cost-share upon successful commercialization of the technology being demonstrated. Implementation Process. Public and private sector involvement is integral to the CCT Program process and was crucial to the program’s success. Environmental concerns are publicly addressed through the process instituted under the National Environmental Policy Act (NEPA). Through programmatic environ- mental assessments (PEAs) and environmental impact statements (PEISs), project specific environmental assessments (EAs) and environmental impact state- ments (EISs), and other NEPA documents, the public is able to comment and have its comments addressed before the projects proceed to implementation. In addition, environmental monitoring programs are required for all projects to address non-regulated pollutant emissions. As to the solicitation process, Congress set the goals for each solicitation. The Department of Energy translated the congressional guidance into perfor- mance-based criteria and developed approaches to address “lessons learned” from previous solicitations. The criteria and solicitation procedures were offered for public comment and presented at pre-proposal conferences. The solicitations were objectively evalu- ated against the pre-established criteria. Projects are managed by the participants, not the government. However, to protect the public interest, safeguards are implemented to track and monitor project progress and direction. The Department of Energy interacts with the project at key negotiated decision points (budget periods) to approve or disap- prove continuance of the project. Also, any changes to cost or other major project changes require DOE approval. In addition to formal project reporting requirements, an outreach program was instituted to make project information available to customers and stakeholders. This Program Update 1999 is only one of the many public reports made available through the outreach program. Commitment to Commercial Realization. The CCT Program has focused on achieving commercial realization since the program’s inception. All five solicitations required the potential participants to address the commercial plans and approaches to be used by the participants to achieve full commercializa- tion of the proposed technology. The cooperative agreements contain balanced provisions that provide protection for intellectual property but required the participants to make the technology available under license on a nondiscriminatory basis. Solicitation Results. Each solicitation was issued as a Program Opportunity Notice (PON)—a solicita- tion mechanism for cooperative agreements where the program goals and objectives are defined, but the technology is not defined. The procurements followed specific statutory requirements that would eventually lead to a cooperative agreement between DOE and the participant. The result was a broad spectrum of tech- nologies involving customers and stakeholders from all market segments. In sum, 211 proposals were submit- ted and 60 of those were selected. As of September 1999, a total of 40 projects have been completed or are currently active. These 40 projects are spread across the nation in 18 states. Future Implementation Direction. The future direction of the CCT Program focuses on completing the existing projects as promptly as possible and assuring the collection, analyses, and reporting of the operational, economic, and environmental performance results that are needed to affect commercialization. In FY2000, three projects are scheduled to complete operations. The body of knowledge obtained as a result of the CCT Program is being used in decision making relative to regulatory compliance, forging plans for meeting future energy and environmental demands, and devel- oping the next generation of technologies responsive to ever increasing demands on environmental perfor- mance at competitive costs. Funding and Costs Program Funding. Congress has appropriated a federal budget of $1.8 billion for the CCT Program. For the 40 completed and active projects, the partici- pants have contributed $3.5 billion dollars for a com- bined commitment of more than $5.4 billion. By law, DOE’s contribution can not exceed 50 percent of the total cost of any project. However, industry has stepped forward and cost shared an unprecedented 66 percent of the project funding. Congress has provided CCT Program funding for all five solicitations through appropriation acts and adjustments. Additional activities funded by the CCT Program are the Small Business Innovation Research Program and the Small Business Technology Transfer Program. Funding is also provided for administration and management of the CCT Program. Use of appro- priated funds is controlled and monitored using a variety of financial management techniques. The full government cost-share specified in the cooperative agreement is considered committed to each project; however, DOE obligates funds for the project in incre- ments by budget period. This procedure reduces the government’s financial exposure and assures that DOE fully participates in the decision to proceed with each major phase of project implementation. Cost Sharing. As stated above, DOE’s contribu- tion can not exceed 50 percent of the total cost of any project. Participant cost-sharing is required for all phases of the project. The federal government may share in project cost growth (which is likely to happen for any demonstration project) up to 25 percent of the original project cost. The participant’s contributions must occur as expenses are incurred and can not be Program Update 1999 ES-5 delayed based on forecasted revenues, proceeds, or royalties. Also, prior investments in facilities by partici- pants can not count toward the participant’s share. Recovery of Government Outlays (Recoup- ment). The policy objective of DOE is to recover an amount up the federal government’s financial contribu- tion to each project when a technology is successfully commercialized. Participants are required to submit a plan outlining a proposed schedule for recoupment. CCT Program Accomplishments Marketplace Commitment. The success of the CCT Program ultimately will be measured by the contribution the technologies make to the resolution of energy, economic, and environmental issues. These contributions can only be achieved if the public and private sectors understand that clean coal technologies can increase the efficiency of energy use and enhance environmental performance at costs that are competi- tive with alternative energy options. The demonstra- tions, in conjunction with an aggressive outreach effort, are designed to impart that understanding. Also, the CCT Program is organized from a market perspec- tive with projects placed in four major product lines— environmental control devices, advanced electric power generation, coal processing for clean fuels, and industrial applications. A summary of the number of projects having completed operations by category is shown in Exhibit ES-1. The first major product line, environmental con- trol devices, is subdivided into three groups—SO, control technologies, NO, control technologies, and combined SO,/NO, control technologies. Both wet ES-6 Program Update 1999 and dry lime- and limestone-based systems were demonstrated to achieve a range of SO, capture effi- ciencies from 50 to 99 percent. All five of the SO, control technology demonstrations have successfully completed operations. For NO, control technologies, two basic approach- es were used: (1) combustion modification techniques including low-NO, burners, overfire air, advanced controls, and reburning systems; and (2) post-combus- tion techniques using selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) systems. These NO, control techniques were applied in a variety of combinations on a variety of boilers, which are representative of 90 percent of the pre-NSPS boilers, i.e., those boilers built before NSPS were imposed by the Clean Air Act of 1970. The result of the NO, control technology demonstrations is a portfo- to achieve cost-effective SO, and NO, emission reductions. A summary of the results of the completed envi- ronmental control device projects can be found in exhibit ES-2. The commercial successes of the envi- ronmental control devices can be seen in Exhibit ES-3. The second major product line, advanced electric power generation, is subdivided into three groups—(1) fluidized-bed combustion, (2) integrated gasification combined-cycle, and (3) advanced combustion/heat engines. These technologies can be used for repower- ing existing plants and for new plants. For fluidized-bed combustion, two approaches were used: atmospheric fluidized-bed combustion and pres- surized fluidized-bed combustion. The two AFBC projects use a circulating-bed, as opposed to a bubbling- lio of technologies that can be applied to the full range of Exhibit ES-1 boiler types and used to address | Completed Projects by Application Category today’s pressing environmental concerns, e.g., ozone. Six of Number of Projects tae NO, control aie Application Category Completed Total gy demonstrations have suc- Operations cessfully completed operations. For the seventh project, the Environmental Control Devices final reports were issued, but SO, Control Technology 5 5 the project was extended for NO, Control Technology 6 7 additional demonstration Combined SO,/NO, Control Technology 6 7 activities. Advanced Electric Power Generation Six of the seven combined Fluidized-Bed Combustion 2 5 SO,/NO, control technology Integrated Gasification Combined-Cycle 0 4 rauaeuaaipall aie Advanced Combustion/Heat Engines 0 2 t . uly complete oo Coal Processing for Clean Fuels 3 5 The demonstrations tested a : —— See Industrial Applications 2 5 multiplicity of complementary Sis Total 24 40 and synergistic control methods Summary of Results of Completed Environmental Control Technology Projects Exhibit ES-2 Project and Participant Key Results Capital Cost SO, Control Technology 10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC—North America) Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) Gas suspension absorption (GSA)/electrostatic precipita- tor (ESP}—SO, removal efficiency of 90% at Ca/S molar ratio of 1.4, 18 °F approach to saturation, and 0.12% chloride (3.0% sulfur bituminous coal) GSA/pulse jet baghouse—SO, removal efficiency 35% greater than GSA/ESP (3.0% sulfur bituminous coal) SO, reduction of 50% (1.2-2.5% sulfur bituminous coal) SO, removal efficiency of 70% at 2.0 Ca/S molar ratio (2.0-2.8% sulfur bituminous coal) SO, removal efficiency of 95% or more at availabilities of 99.5% when operating on 2.0-4.5% sulfur bituminous coal Maximum SO, removal efficiency of 98% Over 3-year demonstration, 237,000 tons of SO, removed while producing 210,000 tons of gypsum Gypsum purity—97.2% Power consumption—5,275 kW (61% of expected) Water consumption—1,560 gal/min (52% of expected) SO, removal efficiency of over 95% at SO, inlet concentrations of 1,000—3,500 ppm using 3% sulfur coal Particulate removal efficiency of 97.7—99.3% at inlet mass loadings of 0.303—1.392 Ib/10° Btu Agricultural-grade gypsum as a by-product Fiberglass-reinforced-plastic construction—chemically and structurally durable; eliminated the need for a flue gas prescrubber and reheat $149/kW for GSA (2.6% sulfur coal) vs. $216/kW for conventional wet limestone forced oxidation (1990$) Less than $30/kW at 500 MWe (4% sulfur coal) (1994$) $66/kW for two reactors (300 MWe); $76/kW for one reactor (150 MWe); $99/kW for one reactor (65 MWe) (1994$) $210/kW at 100 MWe; $121/kW at 300 MWe; $94/kW at 500 MWe (3.0% sulfur coal) (1995$) $313/kW for $408/ton SO, for 100 MWe $131/kW for $171/ton SO, for 300 MWe $104/kW for $136/ton SO, for 500 MWe (Costs based on limestone at $20/ton delivered) Program Update 1999 ES-7 Exhibit ES-2 (continued) Summary of Results of Completed Environmental Control Technology Projects Project and Participant Key Results Capital Cost NO, Control Technology Demonstration of Coal Reburning for Cyclone Boiler NO, Control (The Babcock & Wilcox Company) Full-Scale Demonstration of Low-NO, Cell Burner Retrofit (The Babcock & Wilcox Company) Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler (Energy and Environmental Research Corporation) Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High- Sulfur, Coal-Fired Boilers (Southern Company Services, Inc.) 180-MWe Demonstration of Advanced Tangentially- Fired Combustion Techniques for Reduction of NO, Emissions from Coal-Fired Boilers (Southern Company Services, Inc.) Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) Micronized Coal Reburning Demonstration for NO, Control (New York State Electric & Gas Corporation) L NO, reductions of 52% using bituminous coal and 55% using subbituminous coal at full load (110 MWe); 36% and 53%, respectively, at 60 MWe NO, reductions of 58% using bituminous coal at full load (605 MWe); 48% at 350 MWe LNB alone (second generation)—37% NO, reduction; GR-LNB (second generation}—64% NO, reduction (13% gas heat input) NO, reductions of over 80% at ammonia slip well under 5 ppm NO, reductions of 37% for LNCFS™ I and II, and 45% for LNCFS™ III, which includes both separated overfire air and close-coupled overfire air Using LNB alone, NO, emissions were 0.65 Ib/10° Btu at full load, representing a 48% reduction from baseline conditions (1.24 Ib/10° Btu) Using AOFA only, NO, reductions of 24% below baseline conditions were achieved under normal long-term operation, depending upon load Using LNB/AOFA, full load NO, emissions were approximately 0.40 Ib/10° Btu, which represents a 68% reduction from baseline conditions Using a 14% reburn fuel heat input on the Milliken Station tangentially-fired (T-fired) boiler resulted in a NO, emission rate of 0.25 Ib/10° Btu, which represents a 28% NO, reduction Using a 17% reburn fuel heat input on the Kodak Park cyclone boiler resulted in a NO, emission rate of 0.60 1b/10° Btu, which represents a 59% NO, reduction $66/kW at 110 MWe; $43/kW at 605 MWe (19908) $9/kW at 600 MWe (1994$) GR-LNB $26/kW at 300MWe GR alone $12/kW, plus gas pipeline cost (1996$) Levelized cost at 80% NO, reduction— 2.79 mills/kWh or $2,036/ton of NO, removed (1996$) LNCFS I—$5-15/kW (1993$) LNCFS II/II—$15-25/kW (1993$) Capital cost for a 500 MWe wall-fired unit is $18.8/kW. for LNB/AOFA, $8.8/kW for AOFA alone, $10.0/kW for LNB alone, and $0.5/kW GNOCIS Estimated cost of NO, removal is $86/ton Final results are not yet available, but in general, the capital cost of a micronized coal reburning system exceeds that of a gas reburning system due to milling system costs. On the other hand, the operating cost of a micronized coal reburning system is much lower than a gas reburning system because of the reburn fuel cost differential ES-8 — Program Update 1999 Summary of Results of Completed Environmental Control Technology Projects Exhibit ES-2 (continued) Project and Participant Key Results Capital Cost Combined SO,/NO, Control Technology SNOX™ Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) LIMB Demonstration Project Extension and Coolside Demonstration (McDermott Technology, Inc.) SO,-NO.-Rox Box™ Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) NO, reduction with SCR over 94% at inlet concentra- tions of 500-700 ppm SO, removal efficiency over 95% at inlet concentrations of 2,000 ppm Produced salable sulfuric acid by-product SO, removal efficiency (3.8% sulfur coal, Ca/S molar ratio of 2.0): — LIMB—S3-61% for ligno lime, 51-58% for calcitic lime ~ Coolside—70% for hydrated lime NO, reduction of 40-50% SO, reductions of 80-90% using 3-4% sulfur bituminous coal, depending on sorbent and conditions NO, reduction of 90% with 0.9 NH,/NO, ratio Hennepin—NO, reduction of 67% avg with 18% gas heat input; SO, removal efficiency of 53% at 1.75 Ca/S molar ratio Lakeside—NO, reduction of 66% avg and SO, reductions of 58% during extended continuous combined (GR-SI) runs at 29 MWe, about 22% gas heat input, and 1.8 Ca/S molar ratio The maximum SO, removal demonstrated has been 98% with all seven recycle pumps operating and using formic acid. The maximum SO, removal without formic acid has been 95% Testing of the LNCFS™ III indicated NO, emissions of 0.39 Ib/10° Btu (compared to 0.64 Ib/10° Btu for the original burners) at 36% reduction $305/kW at 500 MWe (3.2% sulfur coal) (1995$) LIMB—$31—102/kW (100-500 MWe) (1992$) Coolside—$69-160/kW (100-500 MWe) (1992$) $233/kW at 250 MWe (3.5% sulfur coal and inlet NO, level of 1.2 1b/10° Btu) (1994$) $15/kW for gas reburning, plus gas pipeline cost (19968) $50/kW for sorbent injection $300/kW at 300 MWe (19988) for total capital requirements $217/kW at 300 MWe for total plant costs and $83/kW for other related costs $4,620,000/yr for O&M costs Program Update 1999 ES-9 Exhibit ES-2 (continued) Summary of Results of Completed Environmental Control Technology Projects Project and Participant Key Results Capital Cost Combined SO,/NO, Control Technology (continued) Integrated Dry NO/SO, Emissions Control System NO, reduction of 62-69% with low-NO, burners and Not yet available (Public Service Company of Colorado) maximum overfire air (50-110 MWe) NO, reduction of 63% with low-NO, burners and minimum overfire air; steady state conditions NO, reduction decreased by 10-25% under load following SNCR obtained NO, reduction of 30-50%, thereby increasing total NO, control system reduction to more than 80% SO, removal efficiency of 70% with sodium bicarbonate at normalized stoichiometric ratio of 1.0 ES-10 Program Update 1999 Exhibit ES-3 Commercial Successes—Environmental Control Technologies Project Commercial Use 10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corp.) LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC-North America) Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) Micronized Coal Reburning Demonstration for NO, Control (New York State Electric & Gas Corp.) Demonstration of Coal Reburning for Cyclone Boiler NO, Control (The Babcock & Wilcox Company) Full-Scale Demonstration of Low-NO, Cell Burner Retrofit (The Babcock & Wilcox Company) Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler (Energy and Environmental Research Corp.) Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers (Southern Company Services, Inc.) Sold domestically and internationally. GSA market entry was significantly enhanced with the sale of a 50-MWe unit, worth $10 million, to the city of Hamilton, Ohio, subsidized by the Ohio Coal Development Office. A sale worth $1.3 million has been made to the U.S. Army for hazardous waste disposal. A GSA system has been sold to a Swedish iron ore sinter plant. Sales to Taiwan, Indonesia, and India have a combined value of $20 million. Furthermore, Taiwan contracted for technical assistance and proprietary equipment valued at $1.0 million. No sales reported. CZD/FGD can be used to retrofit existing plants or for new installations at a cost of about one-fourth the cost of a commercial wet scrubber. Sold domestically and internationally. There are 10 full-scale LIFAC units in operation in Canada, China, Finland, Russia, and the United States. The LIFAC system at Richmond Power & Light is the first to be applied to a power plant using high-sulfur (2.0-2.9%) coal. The LIFAC system has been retained for commercial use by Richmond Power & Light at Whitewater Valley Station, Unit No. 2. No sales reported. The AFGD continues in commercial service at Northern Indiana Public Service Company’s Bailly Generating Station. Gypsum produced by the PowerChip” process is being sold commercially. Sold internationally. Plant Yates continues to operate with the CT-121 scrubber as an integral part of the site’s CAAA compliance strategy. Since the CCT Program demonstration, over 8,200 MWe equivalent of CT 121 FGD capacity has been sold to 16 customers in 7 countries. No sales reported. Technology retained for commercial use at Kodak Power Plant. No sales reported. Technology retained for commercial use at Wisconsin Power and Light Company’s Nelson Dewy Station Sold domestically. Dayton Power & Light has retained the LNCB" for use in commercial service. Seven commercial contracts have been awarded for 172 burners, valued at $27 million. The LNCB* technology has already been installed on more than 4,900 MWe of capacity. Sold domestically and internationally. Public Service Company of Colorado, the host utility, decided to retain the low-NO, burners and the gas-reburning system for immediate use; however, a restoration was required to remove the flue gas recirculation system. Energy and Environmental Research Corporation has been awarded two contracts to provide gas reburning systems for cyclone coal-fired boilers: TVA’s Allen Unit | (a 330-MWe unit) as well as Baltimore Gas & Electric’s C. P. Crane Units | and 2 (similar 200-MWe units). The technology is also installed at Ladyzkin State Power Station in Ladyzkin, Ukraine. No sales reported. SCR has realized commercial acceptance abroad. The demonstration tests established SCR as a viable U.S. compliance option and aided utilities in developing the most cost-effective site-specific applications of SCR. Program Update 1999 ES-11 Exhibit ES-3 (continued) Commercial Successes—Environmental Control Technologies Project Commercial Use 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers (Southern Company Services, Inc.) Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) SNOX™ Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) LIMB Demonstration Project Extension and Coolside Demonstration (McDermott Technology, Inc.) SO,-NO,-Rox Box™ Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corp.) Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corp.) Sold domestically and internationally. LNCFS™ has been retained at the host site for commercial use. ABB Combustion Engineering has modified 116 tangentially fired boilers, representing over 25,000 MWe, with LNCFS™ and derivative TFS 2000™ burners. Sold domestically and internationally. The host has retained the technologies for commercial use. Foster Wheeler has equipped 86 boilers (51 domestic and 35 international) with low-NO, burner technol ogy—a total of 1,800 burners representing over 30,000 MWe capacity valued at $35 million. Twenty-six commercial installations of GNOCIS, the associated AI control system, are underway or planned. This represents over 12,000 MWe of capacity. In a strict sense, this project has not been completed; it has been extended to apply GNOCIS to other pieces of plant equipment, which may increase its commercial potential. International use. The host utility, Ohio Edison, is retaining the SNOX™ technology as a permanent part of the pollution control system at Niles Station to help meet its overall SO, and NO, reduction goals. Commercial SNOX™ plants are also operating in Denmark and Sicily. In Denmark, a 305-MWe plant has operated since August 1991. The boiler at this plant burns coals from various suppliers around the world, including the United States; the coals contain 0.5-3.0% sulfur. The plant in Sicily, in operation since March 1991, has a capacity of about 30 MWe and fires petroleum coke. Sold domestically and internationally. LIMB has been sold to an independent power plant in Canada. Babcock & Wilcox has signed contracts for 124 units for DRB-XCL" low-NO, burners, representing 2,428 burners for 31,467 MWe of capacity. The low-NO, burners have an estimated value of $240 million. No sales reported. Commercialization of the technology is expected to develop with an initial larger scale application equivalent to 50-100 MWe. The focus of marketing efforts is being tailored to match the specific needs of potential industrial, utility, and independent power producers for both retrofit and new plant construction. SNRB™ is a flexible technology that can be tailored to maximize control of SO,, NO,, particulate, or combined emissions to meet current performance requirements while providing flexibility to address future needs. No sales reported. Illinois Power has retained the gas-reburning system and City Water, Light & Power has retained the full technology for commercial use. (See Evaluation of Gas Reburning and Low-NO, Burner on a Wall-Fired Boiler project for a complete understanding of commercial success of the technology.) Sold domestically. Six modules of DHR Technologies’ Plant Emissions Optimization Advisor, with an estimated value of $210,000, have been sold. A U.S. company, SHN, has been established to market the S-H-U scrubber. SHN is pursuing an advanced flue gas desulfurization bid for a Pennsylvania site. ABB Combustion Engineering has modified 116 units representing over 25,000 MWe with LNCFS™ or its derivative TFS 2000™. ES-12 Program Update 1999 Exhibit ES-3 (continued) Commercial Successes—Environmental Control Technologies Project Commercial Use Milliken Clean Coal Technology Demonstration Project Sold domestically. Six modules of DHR Technologies’ Plant Emissions Optimization Advisor, with an (New York State Electric & Gas Corp.) estimated value of $210,000, have been sold. A U.S. company, SHN, has been established to market the S-H-U scrubber. SHN is pursuing an advanced flue gas desulfurization bid for a Pennsylvania site. ABB Combustion Engineering has modified 116 units representing over 25,000 MWe with LNCFS™ or its derivative TFS 2000™. Integrated Dry NO,/SO, Emissions Control System Sold domestically. The technology was retained by Public Service Company of Colorado for commercial (Public Service Company of Colorado) service at its Arapahoe Station. The Babcock & Wilcox DRB-XCL"* burner that was demonstrated has realized sales of 2,428 burners, representing 31,467 MWe. The burners are valued at $240 million. - Program Update 1999 ES-13 bed, operating at atmospheric pressure to generate steam for electricity production. One project is com- plete and the other project is ongoing. There are three PFBC projects in the CCT Program. The completed PFBC project used a bubbling-bed operating at 16 atmospheres to generate steam and drive a gas turbine in a combined-cycle mode. Two ongoing interrelated PFBC projects will use a circulating-bed operating at 13 atmospheres, also in a combined-cycle mode. Three of the four integrated gasification combined- cycle demonstration projects are in operation. A fourth project is in the design stage. The IGCC projects represent a diversity of gasifier types, cleanup systems, and applications. Two projects are demonstrating advanced combus- tion/heat engine technology. One uses an entrained (slagging) combustor and the other uses a heavy duty diesel fired on a coal-water fuel. Both of these projects are ongoing. Coal Quality Expert (CQEm) || Bait on the foundation of CQIM, CQE brings new dnensions to the fuel analysis and decision-making process. ‘+ Flenible modeling capabilities allow users to represent a broad range of equipment and system arrangement ‘© Specialized apphcaons address specs processes: fuel purchasing. clean a coraphance, and engineering support ** Common data and output across a network supports overall corporate fuel assessment needs ‘The Coal Quality Expert - an overview, ‘The CQE User's Manual A CQE™, a PC-based sofiware tool, can be used to determine the complete costs of various fuel options by integrating the effects of fuel purchase decisions on power plant performance, emissions, and power generation costs. ES-14_ Program Update 1999 A summary of the results of the completed ad- vanced electric power generation projects can be found in Exhibit ES-4. The commercial successes of these projects can be seen in Exhibit ES-5. For the third major product line, coal processing for clean fuels, there are five projects. Three projects are using chemical and physical processes to transform raw coal into high-energy-density environmentally compliant fuels. Another project is converting coal to methanol from coal-derived synthesis gas. A fifth project in this product line is a software program used to assess the environmental and operational perfor- mance and determine the least-cost option for available coals. Two of the five coal processing for clean fuels projects are complete. A summary of the results of the completed coal processing for clean fuels projects can be found in Exhibit ES-6. The commercial successes of the coal processing for clean fuels projects can be seen in Exhibit ES-7. The fourth and final major product line is industri- al applications. This product line is addressing the environmental issues and barriers associated with coal use in industry. There are five diverse projects in this category; three are completed and two are ongoing. A summary of the results of the industrial application projects can be found in Exhibit ES-8. Commercial successes of these projects can be seen in Exhibit ES-9. Market Communications—Outreach, Outreach has been a hallmark of the CCT Program since it’s inception. Commercialization of new technologies requires acceptance by a wide range of interests— customers, manufacturers, suppliers, financiers, gov- ernment, and public interest groups. The CCT Pro- gram has aggressively sought to disseminate key information to this full range of customers and stake- holders and to obtain feedback on changing needs. This dissemination of information takes the form of printed media, exhibits, and electronic media. Printed A Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture)—1996 Powerplant Award presented by Power magazine. A Full-Scale Demonstration of Low-NO, Cell Burner Retrofit Project (The Babcock & Wilcox Company)—1994 R&D 100 Award presented by R&D magazine. Exhibit ES-4 Summary of Results of Completed Advanced Electric Power Generation Projects Project and Participant Key Results Capital Cost Tidd PFBC Demonstration Project (The Ohio Power Company) Nucla CFB Demonstration Project (Tri-State Generation and Transmission Association, Inc.) SO, reduction of 90-95% (Ohio bituminous coal, 24% sulfur) at 1.1—-1.5 Ca/S molar ratio NO, emissions of 0.15—0.33 Ib/10° Btu Particulate emissions of 0.02 Ib/10° Btu Heat rate—10,280 Btu/kWh Combustion efficiency—99.6% Commercially viable design Gas turbine operable in PFBC environment SO, reduction of 70-95% (up to 1.8% sulfur coal), depending on Ca/S molar ratio NO, emissions of 0.18 1b/10° Btu Particulate emissions of 0.0072-0.0125 1b/10° Btu Heat rate—11,600 Btu/kWh Combustion efficiency—96.9-98.9% Commercial viability established $1,263/kW at 360 MWe (1997$) Approximately $1,123/net kW (repowering cost) (1990$) Program Update 1999 ES-15 Exhibit ES-5 Commercial Successes—Advanced Electric Power Generation Technologies Project Commercial Use Tidd PFBC Demonstration Project (The Ohio Power Company) Nucla CFB Demonstration Project (Tri-State Generation and Transmission Association, Inc.) Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company) Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) Healy Clean Coal Project (Alaska Industrial Development and Export Authority) Sold internationally. Success of the project has led Babcock & Wilcox to invest in the technology and acquire domestic licensing rights. Commercial ventures abroad include the following: — Vartan Sweden is operating two P200 units to produce 135 MWe and 224 MWt — Escatron in Spain is operating one P200 unit producing 80 MWe — Wakamatsu in Japan is operating one P200 unit to produce 71 MWe — Cottbus in Germany is operating one P200 unit to produce 71 MWe and 40 MWt — Karita in Japan operates one P800 unit to produce 360 MWe — Other projects under construction are in China, South Korea, U.K., and Israel Sold domestically and internationally. Today, every major boiler manufacturer offers an ACFB system in its product line. Since the demonstration, commercial sales of 29 units greater than 100 MWe have been realized, representing 6.2 gigawatts of capacity valued at nearly $6 billion. Sold domestically and internationally. First greenfield IGCC unit in commercial service. Texaco, Inc., and ASEA Brown Boveri signed an agreement forming an alliance to market IGCC technology in Europe. There are currently 10 projects using a Texaco gasifier that are either planned or under construction. No sales reported. First repowered IGCC unit in commercial service and world’s largest single train IGCC in commercial service. Preferentially dispatched over other coal-fired units in PSI Energy’s system because of high efficiency. No sales reported. TRW offering licensing of combustor worldwide (China agreement in place). ES-16 Program Update 1999 Exhibit ES-6 Summary of Results of Completed Coal Processing for Clean Fuels Projects Project and Participant Key Results Capital Cost Development of the Coal Quality Expert™ (ABB Combustion Engineering, Inc. and CQ Inc.) ENCOAL® Mild Gasification Project (ENCOAL Corporation) CQE™ features: - Fuel evaluator—performs system-, plant-, and/or unit- level fuel quality, economic, and technical assessments - Plant engineer—provides in-depth performance evalua- tions with a more focused scope than provided in the fuel evaluator - Environmental planner—provides access to evaluation and presentation capabilities of the Acid Rain Advisor - Coal cleaning expert—establishes the feasibility of cleaning a coal, determines cleaning processes, and predicts associated costs The liquid (CDL”) and solid (PDF") product fuels have been used economically in commercial boilers and furnaces and have reduced SO, and NO, emissions significantly at utility and industrial facilities currently burning high-sulfur bituminous coal or fuel oils Almost five years of operating data have been collected for use as a basis for the evaluation and design of a commercial plant About 260,000 tons of coal had been processed into 120,000 tons of PDF® and 5,101,000 gallons of CDL” CQE™ package sells for between $75,000 and $100,000 A commercial plant designed to process 15,000-metric- ton/day would cost $475 million (2001$) to construct with annual operating and maintenance costs of $52 million per year Program Update 1999 ES-17 Exhibit ES-7 Commercial Successes—Coal Processing for Clean Fuels Technologies Project Commercial Use Development of the Coal Quality Expert™ (ABB Combustion Sold domestically and internationally. The Electric Power Research Institute (EPRI) owns the software Engineering, Inc. and CQ Inc.) and distributes it to EPRI members for their use. CQ Inc. and Black and Veatch have signed commercialization agreements that give both companies nonexclusive worldwide rights to sell user licenses and offer consulting services that include use of CQE*. More than 35 U.S. utilities and one U.K. utility have received CQE® through EPRI membership. Two modules of the Acid Rain Advisor valued at $6,000 have been sold. It is estimated that CQE® saves U.S. utilities about $26 million annually. ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) Domestic and international sales pending. In order to determine the viability of potential LFC® plants, five detailed commercial feasibility studies—two Indonesian, one Russian, and two U.S. projects—have been completed. Permitting of a 15,000 metric-ton/day commercial plant in Wyoming is nearly complete. Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) _No sales reported. Total sales of SynCoal” product exceed 1.5 million tons. Six long-term agreements are in place to purchase the product. One domestic and five international projects have been investi gated. Western SynCoal LLC has a joint marketing agreement with Ube Industries of Japan providing Ube non-exclusive marketing rights outside of the United States. Ube is pursuing several projects in Asia. Western SynCoal is also discussing a potential marketing and development agreements with a U.S. engineering firm. Commercial-Scale Demonstration of the Liquid Phase Methanol No sales reported. Nominal 80,000 gallon/day methanol production being used by Eastman Chemical (LPMEOH™) Process (Air Products Liquid Phase Conversion Company Company , L.P.) ES-18 — Program Update 1999 Exhibit ES-8 Summary of Results of Completed Industrial Application Projects Project and Participant Key Results Capital Cost Advanced Cyclone Combustor with Internal Sulfur, SO, reduction of over 80% with sorbent injection; 58% Not available Nitrogen, and Ash Control (Coal Tech Corporation) maximum with limestone injection at 2.0 Ca/S molar ratio NO, emissions of 160-184 ppm (75% reduction) Slag/sorbent retention of 55-90% in combustor; inert slag Cement Kiln Flue Gas Recovery Scrubber (Passama- SO, reduction of 90-95% (2.5-3% sulfur bituminous $10 million for 450,000 ton/yr wet-process plant (1990$) quoddy Tribe) coal); 98% maximum reduction NO, reduction of 18.8% avg Particulate emissions of 0.005—0.007 gr/std ft? with loading of 0.04 gr/std ft* Exhibit ES-9 Commercial Successes—Industrial Application Technologies Project Commercial Use Advanced Cyclone Combustor with Internal No sales reported. While the combustor was not yet fully ready for sale with commercial guarantees, it was believed to Sulfur, Nitrogen, and Ash Control (Coal Tech have commercial guarantees, it was believed to have commercial potential. Subsequent work was undertaken, which Corporation) has brought the technology close to commercial introduction. Cement Kiln Flue Gas Recovery Scrubber No sales reported. The scrubber became a permanent part of the cement plant at the end of the demonstration. A (Passamaquoddy Tribe) feasibility study has been completed for a Taiwanese cement plant. Blast Furnace Granular-Coal Injection System Domestic sale. British Steel’s Blast Furnace Granular Coal Injection System was sold and installed on a facility owned Demonstration Project (Bethlehem Steel by United States Steel Corporation. Corporation) Program Update 1999 ES-19 media is available through newsletters, proceedings, technical papers, fact sheets, program updates, and bibliographies. The CCT Program currently uses four traveling exhibits of varying sizes and complexity that can be updated and tailored to specific forums. Elec- tronic media is available through the World Wide Web. Upon entering the 21“ century, DOE is making more information available via the World Wide Web. Feedback is another important part of the outreach effort. From public meetings during the PON process to open houses at demonstration sites, the CCT Pro- gram stays in contact with customers and stakeholders. Executive seminars, stakeholder meetings, conferences, workshops, and trade missions are used by the CCT Program to disseminate information and obtain feed- back. A premier CCT Program outreach event is the annual clean coal technology conference. The Seventh Clean Coal Technology Conference was held in Knoxville, Tennessee from June 21-24, 1999. The conference focused on “21% Century Coal Utilization: Prospects for Economic Viability, Global Prosperity, and a Cleaner Environment” to realize the full commercial potential of clean coal technologies. Various sessions were held to discuss topics related to the prospects of coal use in the 21* century. A Knoxville, TN hosted the Seventh Clean Coal Conference in June 1999. The conference attendees included 230 people from over 12 countries. ES-20 Program Update 1999 In addition to the Seventh Clean Coal Technology Conference, several domestic and international confer- ences and workshops were attended or sponsored in fiscal year 1999, The forums for conferences varied from Ankara, Turkey to Baltimore, Maryland. Trade missions during fiscal year 1999 included China, India, Poland, Russia, Taiwan, and Ukraine. All of these events were used to endorse and promote the technolo- gies demonstrated in the CCT Program. CCT Projects Technology Overview. The 40 CCT Program projects provide a portfolio of technologies that will enable coal to continue to provide low-cost secure energy vital to the nation’s economy while satisfying energy and environmental goals well into the 21° century. Environmental Control Devices. The environ- mental control technologies provide a suite of cost- effective control options for the full range of boiler types. The 19 environmental control device projects are valued at $703 million. These include seven NO, emission control systems installed in more than 1,750 MWe of utility generating capacity, five SO, emissions systems installed on approximately 770 MWe, and seven combined SO,/NO, emission control systems installed or planned for installation on more than 665 MWe of capacity. Advanced Electric Power Generation. To respond to load growth, as well as growing environ- mental concerns, the CCT Program provides a range of advanced electric power generation options for both repowering and new power generation. These advanced options offer greater than 20 percent reductions in greenhouse gas emissions; SO,, NO,, and particulate emissions far below NSPS; and salable solid and liquid by-products in lieu of solid wastes. Over 1,800 MWe of capacity are represented by 11 projects valued at more than $2.8 billion. These projects will not only provide environmentally sound electric generation in the mid- to late-1990s, but also will provide the dem- onstrated technology base necessary to meet new capacity requirements in the 21* century. Coal Processing for Clean Fuels. Also addressed are approaches to converting run-of-mine coals to high- energy-density, low-sulfur products. These products have application domestically for compliance with the CAAA. Internationally, both the products and process- es have excellent market potential. Valued at $519 million, the five projects in the coal processing for clean fuels category represent a diversified portfolio of technologies. Industrial Processes. Projects were undertaken as well to address pollution problems associated with coal use in the industrial sector. The problems ad- dressed include dependence of the steel industry on coke and the inherent pollutant emissions in coke making; reliance of the cement industry on low-cost indigenous, and often high-sulfur, coal fuels; and the need for many industrial boiler operators to consider switching to coal fuels to reduce operating costs. The five industrial applications projects have a combined value of nearly $1.3 billion. The projects encompass substitution of coal for 40 percent of coke in iron making; integration of a direct iron-making process with the production of electricity; reduction of cement kiln emissions and solid waste generation; demonstra- tion of an industrial-scale slagging combustor; and demonstration of a pulse combustor system. Project Fact Sheets. The core of this Program Update 1999 is the project fact sheets. Two types of fact sheets are provided: (1) a brief two-page overview for ongoing projects or (2) an expanded four-page summary for projects that have successfully completed operational testing. The latter contains a summary of the major results from the demonstrations, as well as sources for obtaining further information. Technology descriptions, costs, and schedules are provided for all projects. A list of the projects with the participant, solicitation, and status is shown in Exhibit ES-10. A list of the award winning CCT Program projects is shown in Exhibit ES-11. Program Update 1999 ES-21 Exhibit ES-10 Project by Application Category Project Environmental Control Devices SO, Control Technologies 10-MWe Demonstration of Gas Suspension Absorption Confined Zone Dispersion Flue Gas Desulfurization Demonstration LIFAC Sorbent Injection Desulfurization Demonstration Project Advanced Flue Gas Desulfurization Demonstration Project Demonstration of Innovative Applications of Technology for the CT-121 FGD Process NO, Control Technologies Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Demonstration of Coal Reburning for Cyclone Boiler NO, Control Full-Scale Demonstration of Low-NO, Cell Burner Retrofit Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler Micronized Coal Reburning Demonstration for NO, Control Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers Combined SO /NO Control Technologies Commercial Demonstration of the NOXSO SO,/NO, Removal Flue Gas Cleanup System SNOX™ Flue Gas Cleaning Demonstration Project SO.-NO.-Rox Box™ Flue Gas Cleanup Demonstration Project Enhancing the Use of Coals by Gas Reburning and Sorbent Injection LIMB Demonstration Project Extension and Coolside Demonstration Milliken Clean Coal Technology Demonstration Project Integrated Dry NO,/SO, Emissions Control System Advanced Electric Power Generation Fluidized-Bed Combustion Melntosh Unit 4A PCFB Demonstration Project McIntosh Unit 4B Topped PCFB Demonstration Project JEA Large Scale CFB Combustion Demonstration Project Shaded area indicates projects having completed operations. Participant AirPol, Inc. Bechtel Corporation LIFAC-North America Pure Air on the Lake, L.P. Southern Company Services, Inc. Southern Company Services, Inc. The Babcock & Wilcox Company The Babcock & Wilcox Company Energy and Environmental Research Corp. New York State Electric & Gas Corp. Southern Company Services, Inc. Southern Company Services, Inc. NOXSO Corporation ABB Environmental Systems The Babcock & Wilcox Company Energy and Environmental Research Corp. McDermott Technology, Inc. New York State Electric & Gas Corp. Public Service Company of Colorado City of Lakeland, Lakeland Electric City of Lakeland, Lakeland Electric JEA Solicitation/Status CCT-III/completed 3/94 CCT-III/completed 6/93 CCT-III/completed 6/94 CCT-II/completed 6/95 CCT-II/completed 12/94 CCT-II/extended CCT-II/completed 12/92 CCT-III/completed 4/93 CCT-III/completed 1/95 CCT-IV/completed 9/99 CCT-II/completed 7/95 CCT-II/completed 12/92 CCT-III/on hold CCT-II/completed 12/94 CCT-II/completed 5/93 CCT-l/completed 10/94 CCT-I/completed 8/91 CCT-IV/completed 6/98 CCT-III/completed 12/96 CCT-III/design CCT-V/design CCT-I/design ES-22 Program Update 1999 Exhibit ES-10 (continued) Project by Application Category Project Participant Solicitation/Status Tidd PFBC Demonstration Project The Ohio Power Company CCT-I/completed 3/95 Nucla CFB Demonstration Project Tri-State Generation and Transmission Association, Inc. CCT-I/completed 1/91 Integrated Gasification Combined Cycle Kentucky Pioneer Energy IGCC Demonstration Project Kentucky Pioneer Energy, L.L.C. CCT-V/design Pifion Pine IGCC Power Project Sierra Pacific Power Company CCT-IV/operational Tampa Electric Integrated Gasification Combined-Cycle Project Tampa Electric Company CCT-II/operational Wabash River Coal Gasification Repowering Project Wabash River Coal Gasification Repowering Project Joint Venture | CCT-1V/operational Advanced Combustion/Heat Engines Healy Clean Coal Project Alaska Industrial Development and Export Authority CCT-II/operational Clean Coal Diesel Demonstration Project Arthur D. Little, Inc. CCT-V/construction Coal Processing for Clean Fuels Commercial-Scale Demonstration of the Liquid Phase Methanol Air Products Liquid Phase Conversion Company, L.P CCT-III/operational (LPMEOH™) Process Self-Scrubbing Coal™: An Integrated Approach to Clean Air Custom Coals International CCT-IV/on hold Advanced Coal Conversion Process Demonstration Western SynCoal LLC CCT-I/operational Development of the Coal Quality Expert™ ABB Combustion Engineering, Inc., and CQ Inc. CCT-I/completed 12/95 ENCOAL® Mild Coal Gasification Project ENCOAL Corporation CCT-III/completed 7/97 Industrial Applications Clean Power from Integrated Coal/Ore Reduction (CPICOR™) CPICOR™ Management Company L.L.C. CCT-V/design Pulse Combustor Design Qualification Test ThermoChem, Inc. CCT-IV/design Blast Furnace Granular-Coal Injection System Demonstration Project Bethlehem Steel Corporation CCT-III/completed 9/99 Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, Coal Tech Corporation CCT-I/completed 5/90 and Ash Control Cement Kiln Flue Gas Recovery Scrubber Passamaquoddy Tribe CCT-II/completed 9/93 | Shaded area indicates projects having completed operations. Program Update 1999 ES-23 Exhibit ES-11 Award-Winning CCT Projects Project and Participant Award Full-Scale Demonstration of Low-NO, Cell Burner Retrofit (The Babcock & Wilcox Company) Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler; Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Demonstration of Innovative Applications of Technol- ogy for the CT-121 FGD Process (Southern Company Services, Inc.) Tidd PFBC Demonstration Project (The Ohio Power Company) Tampa Electric Integrated Gasification Combined- Cycle Project (Tampa Electric Company) Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) Development of the Coal Quality Expert™ (ABB Combustion Engineering, Inc. and CQ Inc.) 1994 R&D 100 Award presented by R&D magazine to the U.S. Department of Energy for development of the low-NO, cell burner. 1997 J. Deanne Sensenbaugh Award presented by the Air and Waste Management Association to the U.S. Department of Energy, Gas Research Institute, and U.S. Environmental Protection Agency for the development and commercialization of gas-reburning technology. 1993 Powerplant Award presented by Power magazine to Northern Indiana Public Service Company’s Bailly Generating Station. 1992 Outstanding Engineering Achievement Award presented by the National Society of Professional Engineers. 1995 Design Award presented by the Society of Plastics Industries in recognition of the mist eliminator. 1994 Powerplant Award presented by Power magazine to Georgia Power’s Plant Yates. Co-recipient was the U.S. Department of Energy. 1994 Outstanding Achievement Award presented by the Georgia Chapter of the Air and Waste Management Association. 1993 Environmental Award presented by the Georgia Chamber of Commerce. 1992 National Energy Resource Organization award for demonstration of energy-efficient technology. 1991 Powerplant Award presented by Power magazine to American Electric Power Company’s Tidd project. Co-recipient was The Babcock & Wilcox Company. 1997 Powerplant Award presented by Power magazine to Tampa Electric’s Polk Power Station. 1996 Association of Builders and Contractors Award presented to Tampa Electric for quality of construction. 1993 Ecological Society of America Corporate Award presented to Tampa Electric for its innovative siting process. 1993 Timer Powers Conflict Resolution Award presented to Tampa Electric by the state of Florida for the innovative siting process. 1991 Florida Audubon Society Corporate Award presented to Tampa Electric for the innovative siting process. 1996 Powerplant Award presented by Power magazine to CINergy Corp./PSI Energy, Inc. 1996 Engineering Excellence Award presented to Sargent & Lundy upon winning the 1996 American Consulting Engi- neers Council competition. In 1996 recognized by then Secretary of Energy Hazel O’Leary and EPRI President Richard Balzhiser as the best of nine DOE/EPRI cost-shared utility R&D projects under the Sustainable Electric Partnership Program. ES-24 — Program Update 1999 1. Role of the CCT Program Introduction Over the past quarter century, both the national and international energy pictures have been one of dynamic change. These include the oil embargoes of the 1970s and the environmental debates of the 1980s. The 1990s brought about more changes in response to required emission reductions for acid rain precursors, initiation of more stringent NO, standards for ozone nonattainment areas, tighter standards on fine particulates, the beginning of electric utility restruc- turing, and concern about global warming. Since 1985, a joint effort between government and industry, known as the Clean Coal Technology Dem- onstration Program (CCT Program), has responded to the challenges resulting from these dynamic changes. The magnitude of the projects and extent of industry participation in the CCT Program is unprecedented. More than $5.4 billion is being expended, with indus- try and state governments investing two dollars for every federal government dollar invested. With 60 percent of the projects having completed operations by the end of fiscal year 1999, the technological successes have manifested themselves in the market- place. New technologies to reduce the emissions of acid rain precursors, namely sulfur dioxide (SO,) and nitrogen oxides (NO. ), are now in the marketplace and are being used by electric power producers and heavy industry. Advanced electric power generation sys- tems that generate electricity with greater efficiency and fewer environmental consequences are now operating with the nation’s most plentiful fossil energy resource—coal. Coal, which accounts for over 94 percent of the proven fossil energy reserves in the United States, supplies the bulk of the low- cost, reliable electricity vital to the nation’s economy and global competitiveness. According to the U.S. Department of Energy’s (DOE) Energy Information Administration (EIA) Annual Energy Review 1998 (July 1999) (AER98), 933 million tons of coal were used to produce over 1,872 billion kilowatt-hours or 52 percent of the nation’s electricity in 1998. EIA projections count on coal continuing to dominate electric power production, at least through 2020 (the end of the forecast period). In the Annual Energy Outlook 2000 (December 1999) (AEO2000), EIA estimates 1,177 million tons of coal will gener- ate an estimated 2,347 billion kilowatt-hours or nearly 49 percent of all electricity generated in 2020. The ability of coal and coal technologies to respond to the nation’s need for low-cost, reliable electricity hinges on the ability to meet two central requirements: (1) environmental performance requirements established in current and emerging laws and regulations, and (2) operational and economic performance requirements to compete in the era of utility restructuring and competition. The CCT Program is responding to these requirements by producing a portfolio of advanced coal-based technologies that will enable coal to retain its prominent role in the nation’s power generation future. Furthermore, advanced technologies emerg- ing from the CCT Program will also enhance coal’s competitive position in the industrial sector. For example, technology advances in steel making, involving direct use of coal, will reduce the cost of production while greatly improving environmental performance. Also, coal could increase its market share in the industrial sector through cogeneration (steam and electricity) and coproduction of products (clean fuels and chemicals). While the CCT Program responds to domestic needs for competitive and clean coal-based technology, it also positions U.S. industry to compete in a bur- geoning power market abroad. Electricity continues to be the most rapidly growing form of energy consump- tion in the world. Projections from EIA’s /nternation- al Energy Outlook 1999 (March 1999) (IEO99) show electricity rising from 12 trillion kilowatt-hours in 1996 to almost 22 trillion kilowatt-hours in 2020. The strongest growth is projected for the coal-dependent developing countries of Asia. This growth not only represents a tremendous market opportunity, but an opportunity to make a reduction in global carbon emissions through the application of highly efficient clean coal technologies. Coal Technologies Respond to Need The environmentally sound and competitive performance of modern coal technologies has evolved through many years of industry and government research, development, and demonstration (RD&D). The programs were pursued to assure that the U.S. recoverable coal reserves of 274 billion tons, which Program Update 1999 1-1 represent a secure, low-cost energy source, could continue to supply the nation’s energy needs econom- ically and in an environmentally acceptable manner. During the 1970s and early 1980s, many of the government-sponsored technology demonstrations focused on synthetic fuels production technology. Under the Energy Security Act of 1980, the Synthetic Fuels Corporation (SFC) was established for the purpose of reducing the U.S. vulnerability to disrup- tions of crude oil imports. The SFC’s purpose was accomplished by encour- aging the private sector to build and operate synthetic fuel production facilities that would use abundant domestic energy resources, primarily coal and oil shale. The strategy was for the SFC to be primarily a financier of pioneer commercial and near-commer- cial scale facilities. The goal of the SFC was to achieve production capacities of 500,000 barrels per day of synthetic fuels by 1987 and 2 million barrels per day by 1992, at an estimated cost of $8.8 billion. By 1985, it became apparent that the need for synthetic fuels had changed, as oil prices declined, world oil supplies stabilized, and a short-term supply buffer was provided by the Strategic Petroleum Reserve. In 1986, Congress responded to the decline of private-sector interest in the production of synthet- ic fuels in light of these market conditions. Public Law 99-190, Department of the Interior and Related Agencies Appropriations Act for Fiscal Year 1986, abolished the SFC and transferred project manage- ment to the Treasury Department. The CCT Program was initiated in October 1984. Public Law 98-473, Joint Resolution Making Continuing Appropriation for Fiscal Year 1985 and Other Purposes, provided $750 million from the Energy Security Reserve to be deposited in a separate 1-2. Program Update 1999 account in the U.S. Treasury entitled The Clean Coal Technology Reserve. The nation moved from an energy policy based on synthetic fuels production to a more balanced policy. This policy established that the nation should have an adequate supply of energy, maintained at a reasonable cost, and consistent with environmental, health, and safety objectives. Energy stability, security, and strength were the foundations for this policy. Coal was recognized as an essential element in this energy policy for the foreseeable future because of the following: * The location, magnitude, and characteristics of the coal resource base are well understood. * The technology and skilled labor base to safely and economically extract, transport, and use coal are available. ¢ A multi-billion dollar infrastructure is in place to gather, transport, and deliver this valuable energy commodity to serve the domestic and international marketplace. * Coal is used to produce over half of the nation’s electric power and is vital to indus- trial processes, such as steel and cement production, as well as industrial power. + This abundant fossil energy resource is secure within the nation’s borders and relatively invulnerable to disruptions because of the coal industry’s production responsiveness and stockpiling capability. * Coal is the fuel of necessity in many lesser developed economies, which provides export opportunities for U.S.-developed, coal-based technologies. Congress recognized that the continued viability of coal as a source of energy was dependent on the demonstration and commercial application of a new generation of advanced coal-based technologies characterized by enhanced operational, economic, and environmental performance. The CCT Program was established to demonstrate the commercial feasibility of clean coal technology applications in response to that need. In 1986, the first solicitation (CCT-I) for clean coal technology projects was issued. The CCT-I solicitation resulted in a broad range of projects being selected in four major product markets—environmental control devices, advanced electric power generation, coal processing for clean fuels, and industrial applications. In 1987, the CCT Program became the center- piece for satisfying the recommendations contained in the Joint Report of the Special Envoys on Acid Rain (1986). A presidential initiative launched a five-year, $5-billion U.S. government/industry effort to curb precursors of acid rain formation—SO, and NO,. Thus, the second solicitation (CCT-II) issued in February 1988 provided for the demonstration of technologies that were capable of achieving signifi- cant emission reductions in SO,, NO,, or both, from existing power plants. These technologies were to be more cost-effective than current technologies and capable of commercial deployment in the 1990s. In May 1989, a third solicitation (CCT-III) was issued with essentially the same objective as the second, but additionally encouraged technologies that would produce clean fuels from run-of-mine coal. The next two solicitations recognized emerging energy and environmental issues, such as global climate change and capping of SO, emissions, and thus focused on seeking highly efficient, economical- ly competitive, and low-emission technologies. Specifically, the fourth solicitation (CCT-IV), released in January 1991, had as its objective the demonstra- tion of energy efficient, economically competitive technologies capable of retrofitting, repowering, or replacing existing facilities while achieving significant reductions in so, and NO, emissions. In July 1992, the fifth and final solicitation (CCT-V) was issued to provide for demonstration projects that significantly advanced the efficiency and environmental perfor- mance of technologies applicable to new or existing facilities. As a result of these five solicitations, a total of 60 government/industry cost-shared projects were selected, of which 40 valued at more than $5.4 billion have either been successfully completed or remain active in the CCT Program. The success of the government/industry CCT Program is directly attributable to the CCT Pro- gram’s responsiveness to public and private sector needs to reduce environmental emissions and maxi- mize economic and efficient energy production. The CCT Program will strengthen the economy, enhance energy security, and reduce the vulnerability of the economy to global energy market shocks. Coal Technologies for Environmental Performance SO, Regulation Acid Rain Mitigation. During the late 1980s, work began on drafting what was to become the Clean Air Act Amendments of 1990 (CAAA). On November 15, 1990, Congress enacted the CAAA as Public Law 101-549. Title 1V, Acid Deposition Control, established emissions reduction targets for SO, and capped SO, emission in the post-2000 timeframe. Title IV is the first large-scale approach to regulating overall emissions levels by using marketable allowanc- es. The utilities can adopt a control strategy that is most cost-effective for their given systems and plants rather than having to apply a “command-and-control” approach wherein the emission-reduction method is specified. The emission reduction requirements for SO, were to be met in two phases. Phase I, which provided for the initial increment of SO, reduction, began on January 1, 1995. The second increment implemented through Phase II began January 1, 2000. Title IV identified 261 generating units (designated as “affect- ed units”) that were required to comply with Phase I. Most of these units are coal-fired with fairly high emission rates. ing units as part of Phase I compliance strategies. Therefore, 435 units are considered Phase I units. Under Phase II, more than 2,500 units are affected. As a result of Phase I, SO, emissions at electric utilities declined from 15.6 million tons in 1990 to 12.5 million tons in 1997, a 20 percent decline. As shown in Exhibit 1-1, switching to low-sulfur coal was the option chosen by more than half of the owners of Phase I affected units. In Phase II, beginning in 2000, emission con- straints on Phase I plants are tightened, and limits are set for the remaining 2,500 boilers at 1,000 plants. With allowance banking, SO, emissions are expected to decline to 11.6 million tons in 2000 and 9.2 million tons by 2010, and will essentially remain at that level through 2020, the end of the forecast period of AEO2000. Since allowance prices are expected to increase after 2000, EIA predicts that 21 Exhibit 1-1 summa- rizes the compliance methods used by Exhibit 1-1 Phase | SO, Compliance Methods the 261 affected % SO, units listed in Title Method No. of % of Reduction from % of Total IV to satisfy Phase | Units Units 1985 Baseline SO, Reduction reqhirements. An Fuel switching/blending 136 52 60 59 additional 174 units . participated in Additional SO, allowances 83 32 16 9 Phase I based on Scrubbers 27 10 83 28 U.S. Environmental Retirements 7 3 100 2 Protection Agency 7 (EPA) rules that Other 8 3 86 2 Total 261 100 345 100 allow a utility to designate substitu- tion or compensat- “Includes reduced coal consumption of 2.5 million tons and 16% reduction in sulfur content. ‘Includes 1 repowered unit, 2 switched to natural gas, and 5 switched to No. 6 fuel oil. Source: The Effects of Title IV of the Clean Air Act Information Administration, March 19 Amendments of 1990 on Electric Utilities: An Update, Energy 97. Program Update 1999 1-3 GWe of capacity will be retrofitted with scrubbers to meet the Phase II goals. Several projects within the CCT Program, listed below, were designated affected units and were required to achieve compliance with Phase | requirements: + Northern Indiana Public Services Company’s Bailly Generating Station, 528-MWe Unit Nos. 7 and 8 (Pure Air advanced flue gas desulfurization scrubber); * Georgia Power Company’s Plant Yates, 100-MWe Unit No. | (Chiyoda Thorough- bred-121 advanced flue gas desulfurization scrubber); + New York State Electric & Gas Corporation’s Milliken Station, 300-MWe Unit Nos. | and 2 (S-H-U formic-acid-enhanced wet limestone scrubber); and * PSI Energy’s Wabash River Station, 262-MWe Unit No. | (repowered with Destec integrated gasification combined-cycle unit). The three Phase I scrubber projects served to redefine the state-of-the-art in wet limestone scrubber technology and the other was the first to introduce integrated gasification combined-cycle as a repower- ing technology. The advanced scrubbers essentially halved the cost of conventional scrubbers of the time. The repowering project represented an option provid- ed under the CAAA that allows a four-year extension (to December 31, 2003) for compliance with Phase II requirements when advanced electric power genera- tion technology is applied. Together with the other projects, the CCT Program has afforded a portfolio of SO, compliance options for the diverse fleet of existing coal-fired electric generating units and the 1-4 Program Update 1999 means to meet future energy and environmental demands. These include advanced scrubbers, low- capital-cost sorbent injection systems, clean high- energy-density fuels from both eastern and western coals, and a range of advanced electric power genera- tion systems. NO, Regulation Acid Rain Mitigation. In Title IV of the CAAA, Congress also required the EPA to establish annual allowable emissions limitations for NO, in two phases. Phase I required NO, reductions from tangentially-fired and dry-bottom wall-fired boilers. These boilers are referred to as Group | boilers. In March 1994, EPA The types of Group | and 2 boilers and the Phase | and INO, emission limits are shown in Exhibit 1-2. In response to the need to formulate NO, emission reductions that were realistic and achievable for Group 1, EPA was able to use data developed during the Southern Company Services’ evaluation of NO, con- trol technologies on wall-fired and tangentially-fired boilers. Furthermore, operational, environmental, and economic data on NO, controls were developed under the CCT Program for all four major boiler types (wall- fired, tangentially-fired, cyclone-fired, and cell-burner), which constitute over 90 percent of the pre-New Source Performance Standard (NSPS) boiler types. In addition, low-NO, burners were installed and tested on promulgated a rule establishing NO, Exhibit 1-200 emission limitations of CAAA NO, Emission Limits 0.45 Ib/10° Btu f . cae . Group 1 Group 2 Phase | NO, Phase II NO, tangentially-fired units Boiler Type Boiler Type Emission Limits’? Emission Limits’ and 0.50 Ib/10° Btu for (Ib/10°Btu) (Ib/10° Btu) wall-fired units. Ulti- . Tangentially-fired mately,a compliance boilers 0.45 0.40 date of January 1, 1996, : Dry-bottom wall- was established. fired boilers’ 0.50 0.46 On December 19, Cel : “ell-burner 1996, a issued a boilers 0.68 rule to implement Cyclone boil 'yclone boiler Phase II. The rule 155 MWe 0.86 established NO. ission limi . Wet-bottom wall- emission limitations fired boilers for additional coal- >65 MWe 0.84 fired boilers (Group 2) Vertically fired boilers 0.80 and reduced the NO, emissions limitations Other than units applying cell-burner technology. on Group | boilers. “Emission limits are Ib/10°Btu of heat input on an annual average basis. a vertically-fired boiler. Low-NO, burners were devel- oped for all boiler types amenable to burner modifica- tion. Asa result, nearly half of the pre-NSPS boilers are equipped with low-NO, burners (LNB). The CCT Program also demonstrated a range of NO, control techniques to address boilers where burner modifica- tion is not practical and to provide methods to en- hance NO, control beyond low-NO, burner capability. These options included coal and gas reburning, selective noncatalytic reduction (SNCR), and selective catalytic reduction (SCR). This portfolio of NO, controls not only will assure that Phase I and II emission reductions are achievable, but will provide the technology base necessary to achieve even greater NO, reductions that may be necessary to meet CAAA Title I requirements or new National Ambient Air Quality Standards (NAAQS) for ozone. Soot and Smog. The Clean Air Act requires EPA to promulgate and periodically revise NAAQS for each air pollutant identified by the agency as meeting certain statutory criteria. For each pollutant, EPA sets a “primary standard” (a concentration level “requisite A NO. emissions at Georgia Power’s Plant Hammond were reduced by 63 percent with Foster Wheeler’s low- NO, burners, shown here, and advanced overfire air. to protect the public health” with an “adequate margin of safety”) and a “secondary standard” (a level “requisite to protect the public welfare”). In July 1997, EPA issued final rules revising the primary and sec- ondary NAAQS for particulate matter (“PM”) and ozone (O,) (commonly referred to as “soot and smog” regulations). For ozone, the standard was tightened from 0.12 parts per million (or 120 parts per billion) of ozone measured over one hour to a new standard of 0.08 parts per million (or 80 parts per billion) measured over eight hours, with the average fourth highest concentration over a three-year period determining whether an area is out of compliance. (Particulate matter rules are addressed later.) On May 14, 1999, the U.S. Court of Appeals for the District of Columbia Circuit remanded EPA’s “soot and smog” regulations, challenging EPA’s legal rationale as well as EPA’s authority to enforce any new ozone standard under the CAAA. The court did not challenge the underlying science. The De- partment of Justice filed a petition for rehearing by the full court on June 28, 1999. As of the end of FY99, EPA is awaiting the court’s decision on whether to rehear the case. EPA is considering reinstating the old one-hour ozone standard nationwide. Since issuing the more protective 8-hour ozone standard, EPA has revoked the one-hour standard in much of the country (wher- ever ozone levels met the old standard). But the court opinion now leaves much of the nation without an adequately enforceable standard for ground-level ozone pollution to guard against deterioration in air quality. EPA is concerned about that possibility in light of recent air quality data showing that the nation- al average ozone level increased five percent in 1998. A Low-NO, burner technologies: ABB Combustion Engineering’s LNCFS™ for tangentially-fired boilers (top left), Foster Wheeler’s low-NO, burner for wall-fired boilers (top right), Babcock & Wilcox’s LNCB" for cell- burner boilers (center), and Babcock & Wilcox’s DRB- XCL* for down-fired boilers (bottom). In addition to the nationwide soot and smog regulations, efforts are underway to address regional ozone issues. Attainment of Ozone Standards (Title I). CAAA Title I established an ozone transport com- mission to address regional transport of pollutants that contribute to ozone nonattainment in the north- east United States. The Northeast Ozone Transport Commission approved a Memorandum of Under- standing in September 1994 stipulating an intent to reduce power plant NO, emissions (a precursor to ozone formation) by as much as 70 percent by 2003. Program Update 1999 1-5 The Ozone Transport Assessment Group (OTAG), a collaborative effort of 37 states and the District of Columbia, was established in June 1995 to address the issue of ozone transport. In response to recommen- dations issued in June 1997 by the OTAG Policy Group, EPA issued a “SIP Call” to 22 states and the District of Columbia. The SIP Call (effective Decem- ber 28, 1998, as EPA’s Ozone Transport Rule) initially required these 23 jurisdictions to submit emission reduction plans by December 30, 1999, on how to cut NO, emissions 85 percent below 1990 rates or achieve a0.15 Ib/10° Btu emission rate by May 2003. Howev- er, shortly after issuing its National Ambient Air Quality Standards (NAAQS) opinion, the Court of Appeals for the D.C. Circuit stayed the deadline for states to submit plans for complying with the SIP call pending further order of the court. The EPA is also formulating a plan for utilities and industries to trade allowances for NO, emissions. The “cap and trade” program would apply to the 23 jurisdictions affected by the SIP Call. Under the plan, the affected jurisdictions would establish a cap on NO, emissions and then give power plants and PM, , Particle Human Hair Magnified 1,000x A This picture illustrates how minute are PM, , particles when compared to a human hair. 1-6 Program Update 1999 industries the flexibility to cut NO, emissions in the most cost-effective manner. Power plants and indus- tries that cut NO, emissions below the caps could sell credits to facilities that could not cut emissions as quickly or cost-effectively. The NO, trading program, similar to the existing SO, trading program, allows sources to pursue various compliance strategies, such as fuel switching; installing pollution control devices, like the devices demonstrated in the CCT Program; or buying allowances from sources that over-complied. New Source Performance Standards. On the national level, the EPA has tightened its NO, emission standards for new electric utility boilers and has changed its rules so that all generation fuels are treated the same. Under the revised New Source Performance Standard (NSPS), electric utility and industrial steam generating units built or modified after July 9, 1997, must meet an emission limit of 1.6 Ib/ MWh regardless of fuel type. For existing sources that become subject to NSPS, the NO, limit will be 0.15 Ib/10° Btu. By basing the standard on electricity output, there is an economic incentive to use more efficient systems. Particulate Regulation Respirable particles. The standard for inhalable particles (PM, , diameter and smaller—established under Title I of the )}—those measuring 10 microns in CAAA remains essentially unchanged, while a new standard for respirable particles (PM, .)—those mea- suring 2.5 micrometers in diameter and smaller—was established under the new “soot and smog” regula- tions. The PM, , regulations sets an annual limit of 15 micrograms per cubic meter, with a 24-hour limit of 65 micrograms per cubic meter under the “soot and smog” regulations mentioned above. The revisions to A Eight SCR catalysts with various shapes and compositions were evaluated side-by-side at Gulf Power’s Plant Crist using high-sulfur coal. NO, reductions of 80 percent were achieved. NAAQS for PM , , could require additional SO, control because many sulfur species are in this size range. Establishing a reliable relationship between fine sulfate emissions and ambient PM , , concentrations could have serious repercussions for coal burning facilities. Hazardous Air Pollutants Hazardous Air Pollutant Monitoring. Under Title III of the CAAA, EPA is responsible for deter- mining the hazards to public health posed by 189 hazardous air pollutants (HAPs), and is required to perform a study of HAPs to determine the public health risks that are likely to occur as a result of power plant emissions. To address this issue, DOE imple- mented a program with industry to monitor HAPs emissions at CCT Program project sites. Objectives of the HAPs monitoring are to (1) improve the quality of HAPs data being gathered, and (2) monitor a broader range of plant configurations and emissions control equipment. As a result of this program, 21 CCT projects are monitoring HAPs, with 11 having been completed by September 1999 (see Appendix C, Exhibit C-7). Ina parallel effort begun in January 1993, EPA, with the participation of DOE under the Coal Re- search and Development Program, the Electric Power Research Institute (EPRI), and the Utility Air Regu- latory Group (UARG), began an emissions data collection program using state-of-the-art sampling and analysis techniques. Emissions data were col- lected from eight utilities representing nine process configurations, several of which were sites for CCT projects. These utilities represented different coal types, process configurations, furnace types, and pollution control methods. The report, A Compre- hensive Assessment of Toxic Emissions from Coal- Fired Power Plants: Phase I Results from the U.S. Department of Energy Study, was released in Sep- tember 1996 and provided the raw data from the emissions testing. The second phase of the DOE/ EPRI effort involves sampling at other sites, includ- ing the CCT Program’s Wabash River, Tampa Electric, and Sierra Pacific integrated gasification Global Climate Change combined-cycle (IGCC) projects. In another DOE study, HAPs data were collected from 16 power plants and reported in Summary of Air The CCT Program had its roots in the reduction of acid rain precursors and was responsive to the recom- Tous rn 5 Utility PA mendations contained in the Joint Report of the oxics Emissions Testing at Sixteen Utility Plants. . . . : ; g . Special Envoys on Acid Rain, as discussed earlier. The report, issued in July 1996, provides an assess- | P y P . Moreover, as concerns over global climate change ment of HAPs measured in the coal, across the major emerged, the CCT Program began to emphasize dem- pollution control devices, and emitted from the stack. . ~ : . onstration of advanced electric power generation The results of the HAPs program have significantl ete . mt Prog bs Sgt ' y technology capable of achieving significantly higher mitigated concerns about a broad range of HAPs . . . coe J : efficiency than conventional systems, thus reducing emission from coal-fired power generation, and fo- 7 carbon emissions. cused attention on mercury. Mercury. Following up on the October 1996 EPA report to Congress, Study of Hazardous Air For example, pressurized fluidized-bed combus- tion (PFBC) technology has efficiencies up to 25 percent higher than conventional coal-fired systems, Pollutant Emissions from Electric Utility Steam ; . ; a Lk G U; h Final R - final which results in a like reduction in carbon emissions. enerating Units—Interim Final Report (final report . 8 F ( P Also, the PFBC technology reduces pollutant emis- was issued February 1998), a new report has been sions far below NSPS, without expensive add-on released by EPA focusing on mercury emissions. so : 7 creased ®Y CusIng ercury © ann emission controls. As a result of the CCT Program’s The Mercury Study Report to Congress, issued December 1997, estimates that the U.S. industrial sources were responsible for Tidd PFBC Demonstration Project and associated releasing 158 tons of mercury into the atmosphere in 1994 and 1995. The EPA estimates that 87 percent of those emis- sions originate from combustion sources such as waste and fossil fuel facilities, 10 percent from manufacturing facilities, 2 percent from area sources, and | percent from other sources. The EPA also identi- fied four specific categories that account for about 80 percent of the total anthropo- genic sources: coal-fired power plants, 33 percent; municipal waste incinerators, 18 percent; commercial and industrial boilers, 18 percent; and medical waste incinera- A Hazardous air pollutants were measured at the Babcock & Wilcox Company’s Demonstration of Coal Reburning for Cyclone Boiler NO, Control at Nelson Dewey Station. tors, 10 percent. Program Update 1999 1-7 L development work, this technology is achieving market penetration, including several commercial sales of this new generation of advanced power system in Japan and Germany. The work at Tidd is also provid- ing the basis for the second generation PFBC demon- strations to be conducted in Lakeland, Florida with funding from the CCT Program. Another very efficient advanced power system is IGCC. There are four IGCC demonstration projects in the CCT Program, representing a diversity of gasifier types and cleanup systems. These projects are pioneer- ing this environmentally friendly technology, which in addition to lower carbon emissions, boasts very low SO, and NO, emissions. The IGCC technology offers flexibility in that new plants can be constructed in modules as demand dictates. Current worldwide market penetration of this technology is approximately 5GW, and demand is growing. Regional Haze In July 1999, EPA published a new rule calling for long-term protection of and improvement in visibility for 156 national parks and wilderness areas across the country. Many environmental groups believe coal- fired power plants are a source of regional haze in the national parks and wilderness areas. During the period 2003-2008, states are required to establish goals for improving visibility in each of these 156 areas and adopt emission reduction strategies for the period extending to 2018. States have flexibility to set these goals based upon certain factors, but as part of the process, they must consider the rate of progress needed to reach natural visibility conditions in 60 years. Coal-fired power plants are likely targets for new controls to reduce regional haze. 1-8 Program Update 1999 Solid Waste The CCT Program also addresses the issue of solid waste. For example, several projects redefined the state-of-the-art in wet flue gas desulfurization. Included in this significant technology improvement was production of commercial-grade gypsum in lieu of the scrubber sludge associated with conventional scrubbers of the early 1990s. Scrubber sludge had been projected to require over 4,500 acres per year for disposal by 2015. Advances under the CCT Program precluded that need. The balance of tech- nologies in the CCT Program also address solid waste concerns by producing salable by-products instead of wastes (e.g., sulfur, sulfuric acid, or fertil- izer) or dry, environmentally benign materials. These dry materials can either be used as construction materials (e.g., for use in soil and road bed stabiliza- tion, or as a cement ingredient), agricultural supple- ments, a means to mitigate mine subsidence and acid mine drainage, or can be readily disposed of in landfills. Toxics Release Inventory Section 313 of the Emergency Planning and Community Right-To-Know Act (EPCRA) and section 6607 of the Pollution Prevention Act (PPA) mandates establishment of a publicly accessible database containing information on the release of toxic chemicals by facilities that manufacture, pro- cess, or otherwise use them. This database is known as the Toxics Release Inventory (TRI). Starting in 2000, electric utilities are required to report on releases of toxic chemicals into the air, water, and land. EPA compiles this data in an online TRI that gives the public access to detailed information about releases of toxic chemicals in their communities. It is expected that electric utilities will exceed chemical manufacturers as the largest emitters of toxic chemi- cals into the environment. Although the emission rates are low for electric utilities, the volume of emissions will likely bring pressure for further reductions. Coal Technologies for Competitive Performance When the CCT Program started in 1985, the electric utility industry was highly regulated. The major uncertainty was the breadth and depth of environmental regulatory requirements that would be imposed on the industry. Even this uncertainty was mitigated by the fact that the environmental control costs could be passed through to the consumer if approved by the state regulatory commission. As long as the utility made prudent investments in plant and equipment, their economic future was fairly stable and predictable. Most industry observers assumed that coal and nuclear energy would carry the burden of baseload generation, oil would be phased out, and natural gas would be used for meeting peak load requirements. By mid-1997, the picture was entirely differ- ent—the utility industry was in the midst of a major restructuring to accommodate a competitive market- place. Under utility restructuring, power generators must assume the risk for new capacity additions. The relatively low capital cost and short lead times for natural gas-based systems makes them the preferred option for the foreseeable future. As a result, projec- tions now call for natural gas to be the fuel of choice for new capacity additions through 2020. During the same period, nuclear-based capacity will decline and coal-based capacity will increase moderately. Consumers became a major factor in pushing for competition and regulatory reform even though regulators provide the oversight necessary to assure that consumers were paying a fair price. Consumer pressures for access to lower priced power have been successful in bringing about competition in retail as well as wholesale power markets. Deregulation of retail markets is occurring at the state level. (The Federal Energy Regulatory Commission (FERC) is prohibited from ordering retail wheeling.) Under the Energy Policy Act of 1992 (EPAct), states continue to have responsibility for regulating (1) any electric company operating within its jurisdiction, (2) any EWG selling electricity wholesale to such a utility, and (3) any holding company that was an associate or affiliate of an EWG selling power to a regulated utility. By the end of fiscal year 1999, twenty-one states had enacted legislation to allow competition in the retail electricity market in one form or another. In three other states, there have been comprehensive regulatory orders issued. Twenty-six states and the District of Columbia are currently investigating deregulation options. Only in two states is there no significant deregulation activity. Under retail dereg- ulation, end users are not required to purchase power from their local utility company, but instead may purchase power from generators or marketers located in other states and regions of the country. In this competitive market environment, power is priced according to market conditions, not necessarily according to generation costs. Advancement in the technology of electricity production is another factor that has had an impact on restructuring. Nonutility generators have taken advantage of these advances, such as aero-derived gas turbines, to generate electricity cheaper than can be achieved using conventional fossil steam or nuclear Exhibit 1-3 Comparison of Energy Projections for Electric Generators generators. The new technologies are often more efficient, less environmentally obtrusive, and can be installed in a very short period of time in capacity modules closely matching the load growth curves. These factors have had a pronounced effect on the utility market for coal and clean coal technology. A comparison of 1985 and 1999 energy projections for coal, natural gas, and oil, which is shown in Exhibit 1-3, illustrates the magnitude of the change that restructuring is playing, as well as environmen- tal regulation discussed previously. According to EIA’s AEO2000, coal is projected to maintain its lead in the production of electricity in 2010 at 50 per- cent; however, that is down from 60 percent when the CCT Program started. The differential has been, for the most part, made up by the growth in natural gas power generation. Nuclear power’s contribution to the nation’s electric power generation in 2010 is expected to drop by almost 30 percent between the 1985 and 1999 projections. Electricity Sales Coal Consumption Gas Consumption? Oil Consumption* % dif = percent difference between the two projections. * — Consumptions by electric generators excluding cogenerators. > Actuals from Annual Energy Outlook 1998, December 1997. A_ National Energy Policy Plan Projections to 2010, U.S. Department of Energy, December 1985. B= Annual Energy Outlook 2000 with Projections to 2020, Energy Information Agency, December 1999. (10° kWh/yr) (10° tons/yr) (10% ft*/yr) (10° barrels/yr) A B % dif A B % dif A B % dif A B % dif 1995 3,018 3,026" 0.3 924 958° 3.7 3.0 3.37° 12 73 110 51 2010 4,176 3,909 -6.4 1,355 1,092 -19.4 1.7 6.45 279 146 77 -47 Program Update 1999 1-9 Industry restructuring and competition will impact coal and coal technologies for the foreseeable future. Utilities are expected to improve their operating efficiencies by using existing plants at higher capacity factors. Contributing to increased capacity factors is a projected drop in generating capacity not only from nuclear plant retirements but capacity losses where stranded costs are not recovered. The EIA has projected that the capacity factor for coal-fired power plants will increase from 68 percent in 1998 to 83 percent in 2020. EIA further predicts that more than 21 GW of new coal-fired capacity is expected to come on line between 1998 and 2020, accounting for almost 7 percent of capacity expansion. During this time, new highly efficient low-emissions power systems will enter the power production markets. New concepts to reduce delivered electricity prices will likely be em- ployed. Examples include minemouth plants that reduce or eliminate the coal transportation cost com- ponent in power production. Also, cogeneration and coproduction systems will be available, which allow the consumer’s cost of electricity to be offset by the profitability of coproducts. Coal Technologies to Sustain Economic Growth It is in the national interest to maintain a multi- fuel energy mix to sustain national economic growth. Coal is a key component of national energy security because of its affordability, availability, and abun- dance within the nation’s borders. The CCT Pro- gram’s strategy leads to the development and deploy- ment of a technology portfolio that enhances the 1-10 Program Update 1999 efficient use of this coal resource while assuring that national and global environmental goals are achieved. The domestic coal resources are large enough to supply U.S. needs for more than 250 years at current rates of production. The United States is increasingly dependent on imported oil as low prices have resulted in decreased domestic oil production for 13 years. That trend was broken in 1995 by an oil production capacity increase of 0.4 million barrels per day. In 1998, net petro- leum imports were 9.8 million barrels per day, or 51 percent of domestic consumption. In its AEO2000 projections for 2020, EIA expects crude oil imports to range from 11.42 to 11.71 million barrels per day depending on oil price. The 4EO2000 reference case for 2020 calls for net imports of 11.59 million barrels per day, which is over 65 percent of the total crude supply. Also, natural gas imports are expected to grow from 14.6 percent of total gas consumption in 1998 to 16.3 percent in 2020. These imports are primarily from Canada, which does not represent a supply stability problem, but does represent a drain on balance of payments. United States coal consumption is equivalent to approximately 3.6 billion barrels of oil per day, which would equate to $44 billion per year. The CCT Program will provide the technologies that will enable coal to continue as a major component in the nation’s economy while achieving the environmental quality that society demands. The domestic and export value of 1998 coal production approaches $60 billion in the U.S. economy. Coal related jobs are dispersed through the mining, transportation, manu- facturing, utility, and supporting industries. A U.S. coal conversion industry could directly reduce the nation’s dependency on imported oil. The economic impact of adding to domestic oil production or reducing the cost of imported oil is very significant. The CCT Program is responding to this opportunity through development and demonstration of mild gasification and liquid-phase methanol production technologies. According to EIA’s AER98, the U.S. exported 84 million tons of coal in 1997. Coal exports to foreign destinations contributed $3.41 billion to the U.S. balance of trade in 1997. Worldwide demand for energy is expected to reach 612 quadrillion Btu by 2020, over 1.6 times the current level. According to the EIA, worldwide coal use in 1996 accounted for about 25 percent of total energy consumption and 38 percent of the energy consumed worldwide for elec- tricity generation. Those market shares are not pro- jected to change substantially through 2020. Exports of U.S. coal are projected to increase to over 58 million tons by 2020. According to the latest DOE projections, the worldwide market for power generation technologies could be as high as $80 billion between 1995 and 2020. Most of the investment will be in developing coun- tries. This market provides opportunities for U.S. technology suppliers, developers, architect/engineers, and other U.S. firms to capitalize on the advantages gained through experiences in the CCT Program. However, aggressive action is needed, as other governments are recognizing the enormous economic benefits that their economies can enjoy if their manu- facturers capture a greater share of this market. Beyond the CCT Program, DOE activities are aimed at creating a favorable export climate for U.S. coal and coal technology. These efforts include: (1) improving the visibility of U.S. firms and their prod- ucts by establishing an information clearinghouse and closer liaison with U.S. representatives in other coun- tries, (2) strengthening interagency coordination of federal programs pertinent to these exports, and (3) improving current programs and policies for facilitat- ing the financing of coal-related projects abroad. Coal Technology for the Future The CCT Program is providing the foundation needed to build a future generation of fossil energy- based power systems capable of meeting the energy and environmental demands of the 21“ century. The POWER a= a ee) aay, Fuel Celt Wigh Efficiency Turbine hardware and attendant databases serve as platforms for power, environmental, and fuels systems that together can meet the long-term goals of the Office of Fossil Energy’s Coal & Power Systems Program. These “Vision 21” goals are delineated in Exhibit 1-4. The expected result is a suite of technology modules capable of using a broad range of fuels (coal; biomass; and forestry, agricultural, municipal, and refinery wastes) to produce a varied slate of high- value commodities (electricity, steam, clean fuels, and chemicals) at greater than 60 percent efficiency and near-zero emissions. First generation systems emerging from the CCT Program provide: (1) the knowledge base to launch commercial systems, which will experience increasing- ly improved cost and performance over time through design refinement; and (2) platforms to test new components, which will result in quantum jumps in cost and performance. Examples of new components include advanced hot gas particulate filtration, hot gas sulfur and alkali removal, air separation membranes, high temperature heat exchangers, artificially intelli- gent controls and sensors, and CO, and hydrogen separation technologies. A strategy of the Vision 21 effort is to develop and spin off such key components to mitigate the risk and cost of integrating the technol- ogies into power, environmental, and fuel system modules. Exhibit 1-4 Vision 21 Objectives Efficiency—Electricity Generation Efficiency—Combined Heat & Power Efficiency—Fuels Plant Only Coal-based systems 60% (HHV); natural gas-based systems 75% (LHV) with no credit for cogenerated steam." Overall thermal efficiency above 85% (HHYV); also meets efficiency goals for electricity.* Fuel utilization efficiency of 75% (LHV) when producing coal derived fuels.* i i FUELS RY Liguics Conversion "it [ i J snare $ Gas Separation Stream Cleanup Process Heat’ Steam Oxygen Membrane Gasification a. Electricity FuelsiChemicals A Vision 21 modules can be combined in a variety of configurations. Shown is one example of modules to produce a variety of energy products. J Environmental Costs Timing The efficiency goal fora plant co-feeding coal and natural gas will be calculated on a pro-rata basis. Likewise, the efficiency goal for a plant producing both electricity and fuels will be calculated on a pro-rata basis. Near-zero emissions of sulfur, nitrogen oxides, particulate matter, trace elements, and organic compounds; 40-50% reduction in CO, emissions by efficiency improvement; 100% reduction with sequestration. Cost of electricity 10% lower than conventional systems; products of Vision 21 plants must be cost-competitive with market clearing prices. Major spinoffs such as improved gasifiers, advanced combustors, high- temperature filters and heat exchangers, and gas separation membranes begin by 2004; designs for most Vision 21 subsystems and modules available by 2012; Vision 21 commercial plant designs available by 2015. Program Update 1999 1-11 2. Program Implementation Introduction The CCT Program founding principles and imple- menting process resulted in one of the most successful cost-shared government/industry partnerships forged to respond to critical national needs. Through five na- tionwide competitions, a total of 60 government/ industry cost-shared projects were selected, of which 40, valued at more than $5.4 billion have either been completed or remain active at the end of fiscal year 1999. For the 40 projects, the industry cost-share is an unprecedented 66 percent. Sixty percent of the projects (24) have successfully completed operations. The balance are moving forward, with operational testing under way for six projects. Over the nine-year period of soliciting and award- ing projects, the thrust of the environmental concerns relative to coal use have changed. Nevertheless, the implementing process allowed the program to remain responsive to the changing needs. The result is a portfolio of technologies and a database of technical and cost information that will enable coal to remain a major contributor to the U.S. energy mix without being a threat to the environment. This result will ensure secure, low-cost energy requisite to a healthy economy well into the 21* century. Success of the CCT Program is measured by the degree to which the operational, environmental, and economic performance of a technology can be project- ed for commercial applications. Decision makers must have a sufficient database to project performance and assess risk for commercial introduction and deploy- ment of new technologies. This need was a driving force in establishing the principles that created the foundation for the implementation process. The government role is non-traditional, moving away from a command-and-control approach to a performance- based approach, where the government sets perfor- mance objectives and industry responds with its ideas and is allowed broad latitude in technical management of the projects. This approach encourages technology innovation and cost-sharing. Industry and the public play major roles in the process, reflecting their respec- tive roles in moving technologies into the marketplace. Implementation Principles The principles underlying the CCT Program were developed after much study of previous government demonstration programs, assessing both positive and negative results. The principles represent a composite of incentives and checks and balances that allows all participants to best apply their expertise and resources. These guiding principles are outlined below. * A strong and stable financial commitment exists for the life of the projects. Full funding for the government’s share of selected projects was appropriated by Congress at the start of the program. This up-front commitment has been vital to getting industry’s response in terms of quantity and quality of proposals received and the achievement of 66 percent cost-sharing. Multiple solicitations spread over a number of years enabled the program to address a broad range of national needs with a portfolio of evolving technologies. Allowing time between solicitations enabled Congress to adjust the goals of the program to meet chang- ing national needs; provided DOE time to revise the implementation process based on lessons learned in prior solicitations; and provided industry the opportunity to develop better projects and more confidently propose evolving technologies. Demonstrations are conducted at commer- cial scale in actual user environments. Typically, a technology is constructed at commercial scale with full system integration, reflective of its intended commercial configura- tion, and operated as a commercial facility or installed on an existing commercial facility. This enables the technology’s performance potential to be judged in the intended commer- cial environment. The technical agenda is determined by industry and not the government. Based on goals established by Congress and policy guidance received, DOE set definitive perfor- mance objectives and performance-based evaluation criteria against which proposals would be judged. Industry was given the flexibility to use their expertise and innovation to define the technology and proposed project in response to the objectives and criteria. DOE Program Update 1999 2-1 2-2 selected the projects based on those that best met the evaluation criteria. Roles of the government and industry are clearly defined and reflect the degree of cost- sharing required. The government plays a significant role up front in structuring the cooperative agreements to protect public interests. This includes negotiating definitive performance milestones and decision points throughout the project. Once the project begins, the industrial participant is responsible for technical management, while the govern- ment oversees the project through aggressive monitoring and engages in implementation only at decision points. Continued government support is assured as long as project milestones and the terms and conditions of the original cooperative agreement continue to be met. At least 50 percent cost-sharing by industry is required throughout all project phases. Industry’s cost-share was required to be tangible and directly related to the project, with no credit for previous work. By sharing essentially in each dollar expended along the way, on at least an equal basis, industry’s commitment to fulfilling project objectives was strengthened. Allowance for cost growth provides an important check-and-balance feature to the program. Statutory provisions allow for additional financial assistance beyond the original agreement in an amount up to 25 percent of DOE’s original contribution. Such financial assistance, if provided, must be cost- shared by the industrial participant at no less Program Update 1999 than the cost-share ratio of the original coopera- tive agreement. This statutory provision recognizes the risk involved in first-of-a-kind demonstrations by allowing for cost growth. At the same time, it recognizes the need for the industrial participant’s commitment to share cost growth and limits the government’s exposure. Industry retains real and intellectual prop- erty rights. The level of cost-sharing warrants the industrial participant retaining intellectual and real property rights and removes potential constraints to commercialization. Industry would otherwise be reluctant to come forward with technologies they have developed to the point of demonstration, relinquishing their competitive position. Industry must make a commitment to commercialize the technology. Consistent with program goals, the industrial participant is required to make the technology available on a nondiscriminatory basis to all U.S. companies that seek, under reasonable terms and condi- tions, to use the technology. While the technol- ogy owner is not forced to divulge know-how to a competitor, the technology must be made available to potential domestic users on reason- able commercial terms. Upon successful commercialization of the technology, repayment up to the govern- ment’s cost-share is required. The repayment obligation occurs only upon successful commer- cialization of the technology. It is limited to the government’s level of cost-sharing and the 20- year period following the demonstration. In summary, these principles provide built-in checks and balances to ensure that the industry and government roles are appropriate and that the govern- ment serves as a risk-sharing partner without impeding industry from using its expertise and getting the tech- nology into the marketplace. Implementation Process Significant public and private sector involvement was integral to the process leading to technology demonstration and critical to program success. Even before engaging in a solicitation, a public process was instituted under the National Environmental Policy Act (NEPA) to review the environmental impacts. A programmatic environmental impact assessment (PEIA), followed by a programmatic environmental impact statement (PEIS), was prepared prior to initiat- ing solicitations. Public comment and resolution of comments were required prior to proceeding with the program. As to the solicitation process, Congress set the goals for each solicitation in the enabling legislation and report language (see Appendix A for legislative history and Appendix B for program implementation history). The Department of Energy translated the congressional guidance and direction into perfor- mance-based criteria, and developed approaches to address lessons learned from previous solicitations. Before proceeding with a solicitation, however, an outline of the impending solicitation and attendant issues and options was presented in a series of regional public meetings to obtain feedback. The public meet- ings were structured along the lines of workshops to facilitate discussion and obtain comments from the broadest range of interests. Comments from the public meetings then were used in preparing a draft solicita- tion, which in turn was issued for public comment. Comments received were formally resolved prior to solicitation issuance. To aid proposers, preproposal conferences were held for the purpose of clarifying any aspects of the solicitation. Further, every attempt was made in the solicitation to impart a clear understanding of what was being sought, how it would be evaluated, and what con- tractual terms and conditions would apply. A section of the solicitation was devoted to helping potential pro- posers determine technology eligibility, and numerical quantification of the evaluation criteria was provided. The solicitation also contained a model cooperative agreement with the key relevant contractual terms and conditions. Project selection and negotiation leading to award were conducted under stringent rules carrying criminal penalties for noncompliance. Proposals were evaluated and projects negotiated strictly against and within the criteria and terms and conditions established in the solicitation. In the spirit of NEPA, information re- quired and evaluated included project-specific environ- mental, health, safety, and socioeconomic aspects of project implementation. Upon project award, another public process was engaged to ensure that all site-specific environmental concerns were addressed. The National Environmen- tal Policy Act requires that a rigorous environmental assessment be conducted to address all potential environmental, health, safety, and socioeconomic impacts associated with the project. The findings can precipitate a more formal environmental impact state- ment (EIS) process, or the findings can remain as an environmental assessment (EA) along with a finding of no significant impact (FONSI). During the EIS pro- cess, public meetings are held for the purpose of dis- closing the intended project activities, with emphasis on potential environmental, health, safety, socioeco- nomic impacts, and planned mitigating measures. Comments are sought and must be resolved before the project can proceed. This process has led to additional actions taken by the industrial participants beyond the original project scope. To facilitate the NEPA process, DOE encouraged environmental data collection through cost-sharing during the negotiation period contingent upon project award. Because of the environmental nature of the CCT Program, DOE took a proactive posture in carrying out the principles of NEPA. Environmental concerns were aggressively addressed and the public engaged prior to major expenditure of public funds. Furthermore, DOE required that an in-depth environmental monitoring plan (EMP) be prepared, fully assessing potential pollutant emissions, both regulated and unregulated, VY The NEPA process assured environmental acceptability of the Healy Clean Coal Project on the border of Denali National Park in Alaska. and defining the data to be collected and the methods for collection. All cooperative agreements required preparation of environmental monitoring reports that provide results of the monitoring activities. As envi- ronmental issues emerged, every effort was made to address them directly with the understanding that commercial technology acceptance hinged on satisfy- ing users and the public as to acceptable environmental performance. Appendix C reviews the proactive environmental stance taken by the program, further delineates the NEPA process, and provides the status of key actions. Projects are managed by the participants, not the government. However, public interests are protected by requiring defined periods of performance referred to as budget periods, throughout the project. Budget periods are keyed to major decision points. A set amount of funds is allotted to each budget period, along with performance criteria to be met before receiving funds for the next budget period. These criteria are contained in project evaluation plans (PEPs). Progress reports and meetings during budget periods serve to keep the government informed. At the decision points, progress against PEPs is formally evaluated, as is the PEP for the next budget period. Financial data is also examined to ensure the partici- pants’ capability to continue required cost-sharing. Failure to perform as expected results in greater government involvement in the decision making process. Proposal of major project changes precipi- tates not only in-depth programmatic assessment, but legal and procurement review as well. Decisions regarding continuance into succeeding budget periods, any increase in funding, or major project changes require the approval of DOE’s Assistant Secretary of Fossil Energy. Program Update 1999 2-3 Beyond the formal process associated with the solicitations, parallel efforts were conducted to inform stakeholders of ongoing events, results, and issues and to engage them in discussion on matters pertinent to ensuring that the program remained responsive to needs. A continuing dialog was facilitated by direct involvement in the projects of a large number of utilities, technology suppliers, and states, as well as key industry-based research organizations (e.g., the Electric Power Research Institute and Gas Research Institute). This was accompanied by executive seminars designed to enhance communications with the utility, indepen- dent power producer, regulatory, insurance underwrit- er, and financial sectors. The approach was to identify those sectors where inputs were missing and then structure seminars to provide information on the program and obtain the executives’ perspectives and suggestions for enhancing program performance. Furthermore, an annual CCT Conference was instituted to serve as a forum for reporting project progress and results and discussing issues affecting the outcome of the CCT Program. And, an outreach program was put in place to ensure that needed information was pre- pared and disseminated in the most efficient manner, leveraging a variety of domestic and international conferences, symposia, and workshops. These activi- ties are discussed in further detail in Section 4. During implementation of the CCT Program, many precedent-setting actions were taken and many innova- tions were used by both the public and private sectors to overcome procedural problems, create new manage- ment systems and controls, and move toward accom- plishment of shared objectives. The experience devel- oped in dealing with complex business arrangements of multi-million dollar CCT projects is a significant asset that has contributed greatly to the CCT Program’s 2-4 — Program Update 1999 success—an asset of value to other programs seeking to forge government/industry partnerships. To docu- ment lessons learned, Clean Coal Technology Pro- gram Lessons Learned was published in July 1994. This report documents the knowledge acquired over the course of the CCT Program through the completion of five solicitations. The report was based on the belief that it is of mutual advantage to the private and public sectors to identify those factors thought to contribute to the program’s success and to point out pitfalls encountered and corrective actions taken. Commitment to Commercial Realization The CCT Program has been committed to com- mercial realization since its inception. The significant environmental, operational, and economic benefits of the technologies being demonstrated in the program will be realized when the technologies achieve wide- spread commercial success. The importance attached to commercial realization of clean coal technologies is highlighted in Senate Report 99-82, which contains the following recommendation for project evaluation criteria: “[t]he project must demonstrate commercial feasibility of the technology or process and be of commercial scale of such size as to permit rapid commercial scale-up.” The commitment to commercial realization recognizes the complementary but distinctive roles of the technology owner and the government. It is the technology owner’s role to retain and use the informa- tion and experience gained during the demonstration and to promote the use of the technology in the domes- tic and international marketplaces. The detailed opera- tional, economic, and environmental data and the experience gained during the demonstration are vital to efforts to commercialize the technology. The govern- ment’s role is to capture, assess, and transfer operation- al, economic, and environmental information to a broad spectrum of the private sector and international com- munity. The information must be sufficient to allow potential commercial users to confidently screen the technologies and to identify those meeting operational requirements. The importance of commercial realiza- tion is confirmed by the requirement in the solicitations and cooperative agreements that the project participant must pursue commercialization of the technology after successful demonstration. A The results of the Tidd PFBC Demonstration Project have helped pave the way to 10 other projects worldwide. The pressure vessel from Tidd is shown above. Each of the five solicitations contained require- ments for the project proposals to include a discussion of the commercialization plans and approaches to be used by the participants. The proposer was required to discuss the following topics: * The critical factors required to achieve com- mercial deployment, such as financing, licens- ing, engineering, manufacturing, and marketing; + A timetable identifying major commercializa- tion goals and schedule for completion; + Additional requirements for demonstration of the technology at other operational scales, as well as significant planned parallel efforts to the demonstration project, that may affect the commercialization approach or schedule; and * The priority placed by senior management on accomplishing the commercialization effort and how the project fits into the various corpora- tions’ business, marketing, or energy utilization strategies. The cooperative agreement contains three mecha- nisms to ensure that the demonstrated technology can be replicated by responsible firms while protecting the proprietary commercial position of the technology owner. These three mechanisms are: * The commercialization clause requires the technology owner to meet U.S. market demands for the technology on a nondiscriminatory basis (this clause “flows down” from the project participant to the project team members and contractors); The clauses concerning rights to technical data deal with the treatment of data developed jointly in the project as well as data brought into the project; and * The patent clause affords protection for new inventions developed in the project. In addition to ensuring implementation of the above project-specific mechanisms, the government role also includes disseminating the operational, envi- ronmental, and economic performance information on the technologies to potential customers and stakehold- ers. To carry out this role, a CCT Outreach Program was established to perform the following functions: * Make the public and local, state, and federal government policy makers aware of the CCTs and their operational, economic, and environ- mental benefits; * Provide potential domestic and foreign users of the technologies with the information needed for decision making; * Inform financial institutions and insurance underwriters about the advancements in technology and associated risk mitigation to increase confidence; and + Provide customers and stakeholders opportuni- ties for feedback on program direction and information requirements. Specific accomplishments of the CCT Outreach Program are discussed in Section 4. A Publications keep stakeholders informed of CCT Program demonstration results. A Exhibits communicate the progress of the CCT Program at worldwide conferences and trade shows. Program Update 1999 2-5 Solicitation Results Each solicitation was issued as a Program Oppor- tunity Notice (PON)—a solicitation mechanism for cooperative agreements where the program goals and objectives are defined but the technology is not. Pro- posals for demonstration projects consistent with the objectives of the PON were submitted to DOE by specific deadlines. DOE evaluated, selected, and negotiated projects strictly within the bounds of the PON provisions. Award was made only after Congress was allowed 30 in-session days to consider the projects as outlined in a Comprehensive Report to Congress issued after each solicitation. Exhibit 2-1 summarizes the results of solicitations. Exhibit 2-2 identifies the projects currently in the CCT Seated oes cele ens A Comprehensive Report to Congress was issued after each solicitation for each selected project. 2-6 Program Update 1999 Program and the solicitation under which the projects were selected. Appendix B Exhibit 2-1 CCT Program Selection Process Summary provides a summary of the procurement history and a PON Issued Projects in CCT Program as of Sept. 30, 1999 Proposals Projects Submitted Selected chronology of project Solicitation selection, negotiation, restructuring, and comple- CCT-I tion or termination. Project CCT-II sites are mapped in Exhibits CCT-III 2-3 through 2-6, which CCT-IV CCT-V indicate the geographic locations of projects by application category. February 17, 1986 February 22, 1988 May 1, 1989 January 17, 1991 July 6, 1992 Sl 17 8 55 16 9 48 13 13 33 9 6 24 5 4 211 60 40 The resultant projects have achieved broad-based industry involvement. More than 55 individual electric generators serving 33 states have participated in the program. These ut ilities . generate more than 178,000 MWe, approximately 25 percent of U.S. capacity, and consume about 36 per- cent of the coal produced domestically. Also partici- pating were over 50 companies supplying technology and 30 providing engineering, construction, and consulting services. The contributions of the selected projects to domestic and international energy and environme! ntal needs are significant. These contributions include: * Completing demonstration and proving commercial viability of a suite of cost-effective SO, and NO, control options capable of achieving moderate (50 percent) to deep ( 95 percent) emission reduction for the full range of coal-fired boiler types; 70- * Providing the database and operating experi- ence requisite to making atmospheric fluidized- bed combustion a commercial technology at utility scale; Completing demonstration of a number of coal processes to produce high-energy-density, low- sulfur solid fuels and clean liquids from a range of coal types: Laying the foundation for the next generation of technologies to meet the energy and environ- mental demands of the 21‘ century—three IGCC plants in operation at three separate utilities; and successful demonstration of pressurized fluidized-bed combustion at 70 MWe and two larger scale demonstrations in progress; and Demonstrating significant efficiency and pollutant emission reduction enhancements in steel making, advanced combustion for com- bined SO,/NO,/PM control for industrial and small utility boilers, and innovative SO, control for waste elimination in cement production. Exhibit 2-2 Clean Coal Technology Demonstration Projects by Solicitation Project and Participant Location CCT-I Development of the Coal Quality Expert™ (ABB Combustion Engineering, Inc. and CQ Inc.) Homer City, PA LIMB Demonstration Project Extension and Coolside Demonstration (McDermott Technology, Inc.) Lorain, OH Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (Coal Tech Corporation) Williamsport, PA Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Hennepin and Springfield, IL Tidd PFBC Demonstration Project (The Ohio Power Company) Brilliant, OH Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) Colstrip, MT Nucla CFB Demonstration Project (Tri-State Generation and Transmission Association, Inc.) Nucla, CO JEA Large Scale CFB Combustion Demonstration Project (JEA) Jacksonville, FL CCT-II SNOX™ Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) Niles, OH Demonstration of Coal Reburning for Cyclone Boiler NO, Control (The Babcock & Wilcox Company) Cassville, WI SO,-NO.-Rox Box™ Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) Dilles Bottom, OH Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) Thomaston, ME Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Chesterton, IN Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) Coosa, GA Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) Newnan, GA Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers Pensacola, FL (Southern Company Services, Inc.) 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Lynn Haven, FL Boilers (Southern Company Services, Inc.) CCT-III Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process (Air Products Liquid Phase Conversion Kingsport, TN Company, L.P.) 10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) West Paducah, KY Healy Clean Coal Project (Alaska Industrial Development and Export Authority) Healy, AK Full-Scale Demonstration of Low-NO, Cell Burner Retrofit (The Babcock & Wilcox Company) Aberdeen, OH Program Update 1999 Exhibit 2-2 (continued) Clean Coal Technology Demonstration Projects by Solicitation Commercial Demonstration of the NOXSO SO,/NO, Removal Flue Gas Cleanup System (NOXSO Corporation) CCT-IV Micronized Coal Reburning Demonstration for NO, Control (New York State Electric & Gas Corporation) Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) Pifion Pine IGCC Power Project (Sierra Pacific Power Company) Pulse Combustor Design Qualification Test (ThermoChem, Inc.) Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) Self-Scrubbing Coal™: An Integrated Approach to Clean Air (Custom Coals International) CCT-V Clean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) Clean Power from Integrated Coal/Ore Reduction (CPICOR™) (CPICOR™ Management Company L.L.C.) Kentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, L.L.C.) McIntosh Unit 4B Topped PCFB Demonstration Project (City of Lakeland, Lakeland Electric) Project and Participant Location CCT-IIl (continued) Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) Seward, PA Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) Burns Harbor, IN McIntosh Unit 4A PCFB Demonstration Project (City of Lakeland, Lakeland Electric) Lakeland, FL ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) Gillette, WY Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler (Energy and Environmental Research Corporation) Denver, CO LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC—North America) Richmond, IN Integrated Dry NO./SO, Emissions Control System (Public Service Company of Colorado) Denver, CO Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company) Mulberry, FL On hold Lansing and Rochester, NY Lansing, NY Reno, NV Baltimore, MD West Terre Haute, IN Central City, PA Fairbanks, AK Vineyard, UT Trapp, KY Lakeland, FL 2-8 Program Update 1999 Exhibit 2-3 Geographic Locations of CCT Projects—Environmental Control Devices Public Service Company of Colorado Energy and Environmental = The Babcock & Wilcox Research Corporation Pure Air on the Lake, L.P. New York State Electric & Gas Corporation Company Denver, CO Denver, CO Cassville, WI Energy and Environmental Research Corporation Hennepin and Springfield, IL AirPol, Inc. West Paducah, KY Chesterton, IN Lansing and Rochester, NY The Babcock & Wilcox Company Lorain, OH New York State Electric & Gas Corporation Lansing, NY ABB Environmental Systems Niles, OH Bechtel Corporation Seward, PA The Babcock & Wilcox Company Dilles Bottom, OH The Babcock & Wilcox Company Aberdeen, OH LIFAC-North America Richmond, IN Southern Company Services, Inc. Coosa, GA Southern Company Services, Inc. Newnan, GA Southern Company Services, Inc. Lynn Haven, FL Southern Company Services, Inc. Pensacola, FL NOXSO Corporation On hold Program Update 1999 2-9 Exhibit 2-4 Geographic Locations of CCT Projects—Advanced Electric Power Generation Wabash River Coal Gasification The Ohio Power Repowering Project Joint Venture Company West Terre Haute, IN Brilliant, OH Kentucky Pioneer Energy, LLC Trapp, KY Sierra Pacific Power Company Reno, NV JEA Jacksonville, FL Alaska Industrial Development and Export Authority Healy, AK City of Lakeland, Lakeland, FL (2 projects) Tri-State Generation Tampa Electric Company and Transmission Mulberry, FL Association, Inc. Nucla, CO Arthur D. Little, Inc. Fairbanks, AK 2-10 Program Update 1999 Exhibit 2-5 Geographic Locations of CCT Projects—Coal Processing for Clean Fuels Rosebud SynCoal ENCOAL Corporation Partnership Gillette, WY Colstrip, MT ABB Combustion Engineering, Inc., and CQ Ine. Homer City, PA Custom Coals International Central City, PA Air Products Liquid Phase Conversion Company, L.P. Kingsport, TN Program Update 1999 2-11 Exhibit 2-6 Geographic Locations of CCT Projects—Iindustrial Applications Bethlehem Steel Corporation Passamaquoddy Tribe Burns Harbor, IN Thomaston, ME Coal Tech Corporation Williamsport, PA ThermoChem, Inc. Baltimore, MD CPICOR™ Management Company, L.L.C. Vineyard, UT be ~ N Program Update 1999 Future Implementation Direction The future implementation direction of the CCT Program focuses on completing the existing projects as promptly as possible and assuring the collection, analyses, and reporting of the operational, economic, and environmental performance results that are needed to affect commercialization. Subsequent to the end of fiscal year 1999, but prior to publication of this report, the cooperative agreement for two demonstration projects expired— NOXSO Corporation and Custom Coals International are in bankruptcy and were not able to restructure and continue work under the CCT Program. Information on NOXSO Corporation’s Commercial Demonstration of the NOXSO SO,/NO, Removal Flue Gas Cleanup System and Custom Coals International’s Self-Scrub- bing Coal™: An Integrated Approach projects are included in this report because there is data that readers may find beneficial. Furthermore, this report is based on the status as of September 30, 1999, and the expira- tion of these cooperative agreements occurred after that date. These two projects will not be included in future reports. In fiscal year 2000, the following projects are forecasted to complete operations: * Pifion Pine IGCC Power Project, * Healy Clean Coal Project, and * Pulse Combustor Design Qualification Test. The body of knowledge obtained as a result of the CCT Program demonstrations is being used in immedi- ate decision making relative to regulatory compliance, forging plans for meeting future energy and environ- mental demands, and developing the next generation of technology responsive to ever-increasing demands on environmental performance at competitive costs. An expanded portfolio of information will be forthcoming to make it easier for stakeholders and customers to sift through the already enormous amount of data resulting from the demonstrations. Efforts will continue toward refining the effective- ness in responding to customer and stakeholder needs. Toward that end, as needs change, forums will be sought to obtain feedback particularly in view of utility restructuring, continued environmental concerns, and a burgeoning foreign market. Objectives are to ensure that CCT Program efforts are fully leveraged and that follow-on efforts under the OC&PS Research, Devel- opment, and Demonstration Program are appropriate. Program Update 1999 2-13 3. Funding and Costs Introduction See CCT Project Costs and Cost-Sharing Congress has appropriated a federal budget of (Dollars in Thousands) $2.3 billion for the CCT Program. These funds have Total Cost-Share Dollars Cost-Share Percent been committed to demonstration projects selected Project Costs % DOE’ Participants DOE Participants through five competitive solicitations. As of Septem- ber 30, 1999, the program consisted of 40 active or Subprogram completed projects. These 40 projects have resulted CCT-I 844,363 16 239,640 604,723 28 72 in a combined commitment by the federal government CCT-II 318,577 6 139,229 179,348 44 56 and the private sector of nearly $5.4 billion. DOE’s CCT-II 1,408,141 26 618,324 789,817 44 56 cost-share for these projects exceeds $1.8 billion, or CCT-IV 1,037,815 19 477,058 560,757 46 54 approximately 34 percent of the total. The project CCT-V 1,765,009 33 360,982 1,404,027 20 80 participants (i.e., the non-federal-government partici- Total® 5,373,905 100 1,835,233 3,538,672 34. t«t6 pants) are providing the remaining $3.5 billion, or 66 percent of the total. Exhibit 3-1 summarizes the total Application Category costs of CCT projects as well as cost-sharing by DOE Advanced Electric Power 2,864,284 53 1,118,865 1,745,419 39 61 and project participants. Generation The data used to prepare Chapter 3 is based on Environmental Control Devices 702,922 13 294,272 408,650 42 58 the 40 projects that were active in the CCT Program Coal Processing for Clean Fuels 519,196 10 230,024 289,172 44 56 as of September 30, 1999. Since then, the projects Industrial Applications 1,287,503 24 192,072 1,095,431 15 85 sponsored by NOXSO Corporation and Custom Coals Total® 5,373,905 100 1,835,233 3,538,672. 7 34 66 International have ended. Both projects were in bankruptcy and were not able to restructure and * Totals may not add due to rounding. continue work under the CCT Program. Future ° DOE share does not include $52,986,136 obligated for withdrawn projects and audit expenses. reports will not include data for these two projects. Program Update 1999 3-1 Program Funding General Provisions In the CCT Program, the federal government’s contribution can not exceed 50 percent of the total cost of any individual project. The federal govern- ments funding commitments and other terms of federal assistance are represented in a cooperative agreement negotiated for each project in the program. Terms of the cooperative agreement also include a plan for the federal government to recoup up to the full amount of the federal government’s contribution. This approach enables taxpayers to benefit from commercially successful projects. This is in addition to the benefits derived from the demonstration and commercial deployment of technologies that improve environmen- tal quality and promote the efficient use of the na- tion’s coal resources. The project participant has primary responsibility for the project. The federal government monitors project activities, provides technical advice, and assesses progress by periodically reviewing project performance with the participant. The federal govern- ment also participates in decision making at major project junctures negotiated into the cooperative agreement. Through these activities, the federal government ensures the efficient use of public funds in the achievement of individual project and overall program objectives. Exhibit 3-2 Relationship between Appropriations and Subprogram Budgets for the CCT Program (Dollars in Thousands) SBIR Program Appropriation Adjusted & STTR Direction Projects Enacted Subprogram Appropriations Budgets’ Budget Budget P.L. 99-190 CCT-I 380,600 4,902 101,767 273,931 P.L. 100-202 CCT-II 473,959 6,781 32,512 434,666 P.L. 100-446 CCT-III 574,998 6,906 22,548 545,544 P.L. 101-121° CCT-IV 427,000 7,065 25,000 394,935 P.L. 101-121 CCT-V 450,000 5,427 25,000 419,573 Total 2,306,557 31,081 206,827 2,068,649 * Small Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) Programs. ’ P.L. 101-121 was revised by P.L. 101-512, 102-154, 102-381, 103-138, 103-332, 104-6, 104-208, 105-18, 105-83, 105-277, and 106-113. 3-2. Program Update 1999 Congress has provided program funding through appropriation acts and adjustments. (See Appendix A for legislative history and excerpts from the relevant funding legislation.) Exhibit 3-2 presents the allocation of appropriated CCT Program funds (after adjustment) and the amount available for each CCT solicitation. Addition- al activities funded by CCT Program appropriations are the Small Business Innovation Research (SBIR) Program, the Small Business Technology Transfer (STTR) Program, and CCT Program direction. The SBIR Program implements the Small Business Inno- vation Development Act of 1982 and provides a role for small, innovative firms in selected research and development (R&D) areas. The STTR Program implements the Small Business Technology Transfer Act of 1992 that establishes a pilot program and funding for small business concerns performing cooperative R&D efforts. The CCT program direction budget provides for the management and administrative costs of the program and includes federal employees’ salaries, benefits and travel, site support services, and services provided by national laboratories and private firms. Availability of Funding Although all funds necessary to implement the entire CCT Program were appropriated by Congress prior to FY 1990, the legislation also directed that these funds be made available (i.e., apportioned) to DOE on a time-phased basis. Exhibit 3-3 depicts this apportionment of funding to DOE. Exhibit 3-3 also shows the program’s yearly funding profile by appro- priations act and by subprogram. Funds can be transferred among subprogram budgets to meet project and program needs. Exhibit 3-3 Annual CCT Program Funding by Appropriations and Subprogram Budgets (Dollars in Thousands) Fiscal Year 1986-91 1992° 1994° 1995 1996 1997 1998 1999 2000 2001 2002 Total’ Adjusted Appropriations’ P.L. 99-190 397,600 (17,000) 380,600 P.L. 100-202 574,997 (101,000) — (40,000) 9,962 15,000 15,000 473,959 P.L. 100-446 574,998 (156,000) 156,000 574,998 P.L. 101-121’ 35,000 315,000 100,000 18,000 50,000 (91,000) 427,000 P.L. 101-121? 100,000 125,000 19,121 100,000 105,879 450,000 Total 1,582,595 415,000 — 225,000 37,121 150,000 (2,121) (101,000) (40,000) (146,038) 171,000 15,000 2,306,557 Subprogram Budgets CCT-I Projects 387,231 (18,000) (18,000) — (33,000) (15,000) (14,900) (14,400) 273,931 CCT-II Projects 535,704 (101,000) — (40,000) 9,962 15,000 15,000 434,666 CCT-III Projects 545,544 (156,000) 156,000 545,544 CCT-IV Projects 9,875 311,063 98,450 17,622 48,925 (91,000) 394,935 CCT-V Projects 74,062 123,063 18,719 97,850 105,879 419,573 Projects Subtotal 1,478,354 385,125 221,513 18,341 128,775 (18,121) (116,000) (54,900) (160,438) 171,000 15,000 2,068,649 Program Direction 85,527 25,000 18,000 18,000 16,000 15,000 14,900 14,400 206,827 Fossil Energy Subtotal 1,563,881 410,125 221,513 36,341 146,775 (2,121) (101,000) — (40,000) — (146,038) 171,000 15,000 2,275,476 SBIR & STTR* 18,714 4,875 3,487 779 3,225 31,081 Total? 1,582,595 415,000 225,000 37,121 150,000 (2,121) (101,000) (40,000) — (146,038) 171,000 15,000 2,306,557 * Shown are appropriations less amounts sequestered under the Gramm-Rudman-Hollings Deficit Reduction Act. ’ Shown is the fiscal year apportionment schedule of P.L. 101-121 as revised by P.L. 101-512, 102-154, 102-381, 103-138, 103-332, 104-6, 104-208, 105-18, 105-83, 105-277, and 106-113. * Small Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) Programs. “ Totals may not appear to add due to rounding. © No changes were made to funding amounts in 1993. Program Update 1999 3-3 Use of Appropriated Funds There are five key financial terms used by the government to track the status and use of appropriated funds: (1) budget authority, (2) commitments, (3) obligations, (4) costs, and (5) expenditures. The definition of each of these terms is described below. * Budget Authority. This is the legal authori- zation created by legislation (i.e., an appro- priations act) that permits the federal govern- ment to obligate funds. * Commitments. Within the context of the CCT Program, a commitment is established when DOE selects a project for negotiation. The commitment amount is equal to DOE’s share of the project costs contained in the cooperative agreement. * Obligations. The cooperative agreement for each project establishes funding increments, referred to as budget periods. The cooperative agreement defines the tasks to be performed in each budget period. An obligation occurs in the beginning of each budget period and establishes the incremental amount of federal funds available to the participant for use in performing tasks as defined in the cooperative agreement. * Costs. A request for payment submitted by the project participant to the federal govern- ment for reimbursement of tasks performed under the terms of the cooperative agreement is considered a cost. Costs are equivalent to a bill for payment or invoice. ¢ Expenditures. Expenditures represent payment amounts to the project participant from checks drawn upon the U.S. Treasury. 3-4 Program Update 1999 The full government cost-share specified in the cooperative agreement is considered committed to each project. However, DOE obligates funds for the project in increments. Most projects are subdivided into several time and funding intervals, or budget periods. The number of budget periods is determined during negotiations and is incorporated into the cooperative agreement. DOE obligates sufficient funds at the beginning of each budget period to cover the government’s cost-share for that period. This procedure limits the government’s financial exposure and assures that DOE fully participates in the decision to proceed with each major phase of project implementation. The overall financial profile for the CCT Pro- gram is presented in Exhibit 3-4. The graph shows actual performance for FY 1986 through FY 1999 and DOE estimates for FY2000 through program comple- tion. Excluded from the The financial status of the program through September 30, 1999, is presented by subprogram in Exhibit 3-5. SBIR and STTR funds are included in this exhibit to account for all funding. Exhibit 3-5 also indicates the apportionment sequence as modi- fied by Public Law 106-113. These values represent the amount of budget authority available for the CCT Program. Project Funding, Costs, and Schedules Information for individual CCT projects, including funding and the status of key milestones, is provided in Section 5. An overview of project schedules and funding is presented in Exhibit 3-6. graph are SBIR and STTR funds, as these are used and tracked separately from the CCT Program. Exhibit 3-4 CCT Financial Projections? as of September 30, 1999 The financial projections presented in Exhibit 3-4 are based on individual 600,000 500,000 project schedules and 400,000 300,000 budget periods as defined in the cooperative agree- 200,000 100,000 Dollars x 1,000 ments and modifications. The negative Budget 9 Authority values shown in 100,000 Exhibit 3-4 result from ~200,000 rescission of $101 million in FY1998, the deferral of $40 million in FY 1999, and the deferral of $146 UL 86 87 88 89 GE Budget Authority 90 91 92 93 94 95 96 97 98 99 00 O1 02 03 04 05 Fiscal Year ME Costs —4— Obligations “Includes changes resulting from P.L. 106-113. million in FY2000. Exhibit 3-5 Financial Status of the CCT Program as of September 30, 1999° (Dollars in Thousands) Appropriations Apportionment Sequence Subprogram ecioyeny Coll . Dee °c oped sous a annual eve CCT-I 273,931 273,931 257,126 257,126 183,854 1986 99,400 99,400 CCT-II 434,666 404,666 171,198 172,026 165,275 1987 149,100 248,500 CCT-III 545,544 389,544 618,324 618,061 470,076 1988 199,100 447,600 CCT-IV 394,935 394,935 478,389 478,389 463,751 1989 190,000 637,600 CCT-V 419,573 419,573 363,182 148,331 15,840 1990 554,000 1,191,600 Projects Subtotal 2,068,649 1,882,649 7 1,888,219 1,673,933 : 1,298,796 1991 390,995 1,582,595 SBIR & STTR*® 31,081 31,081 31,081 31,081 31,081 1992 415,000 1,997,595 Program Direction 206,827 206,827 192,427 190,847 187,806 1993 0 1,997,595 Total 2,306,557 2,120,557 2,111,727 1,895,861 1,517,683 1994 225,000 2,222,595 1995 37,121 2,259,716 ¢ $mall Business Innovation Research (SBIR) and Small Business Technology Transfer (STTR) Programs 1996 150,000 2,409,716 ’ Totals may not appear to add due to rounding 1997 (2,121) 2,407,595 Includes changes from P.L. 106-113 1998 (101,000) 2,306,595 1999 (40,000) 2,266,595 2000 (146,038) 2,120,557 2001 171,000 2,291,557 2002 15,000 2,306,557 Program Update 1999 3-5 Exhibit 3-6 CCT Project Schedules and Funding, by Application Category NOXSO Corporation - Calendar |86 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006) DOE Total Year 3412341234123412341234123412341234123412341234123412341234123412341234123412341234] ($1,000) B&W--LiMe|_ Environmental Control Devices 7,592 19,311 SCS--Tangentially Fired TE 4,149 8,554 Bechtel -- CZD zs herr 5,206 10,412 B&W--Coal Reburning a 6,341 13,647 B&W--LNCB eS 5443 11,233 ABB ES--SNOX | Ee 15719 31,438 B&W--SNRB mac | 6078 13,272 Pure Air on the Lake [ee 63,913 151,708 LIFAC ar 10,637 21,394 AirPol -- GSA 2315 7717 NYSEG -- Milliken eS Si 45,000 158,608 NYSEG -- Micronized [| EE es 2701 9,096 [on tote 41406 82,812 - Preaward fae] - Design and Construction i - Operation and Reporting 3-6 Program Update 1999 Exhibit 3-6 (continued) CCT Project Schedules and Funding, by Application Category Calendar |86 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006) DOE Total Year 34123412341234123412341 23412341 23412341 23412341 2341234123412341 23412341 23412341234 ($1,000) Tri-State--Nu Advanced Electric Power Generation 17,130 160,050 Wabash River 219,100 438,200 Tampa Electric 150,894 303,288 Sierra Pacifi 167,957 335,913 AIDEA 117,327 242,058 ADL--Coal Diesel 23,818 47,636 JEA 74,734 309,097 McIntosh 4A 93,253 186,588 KY Pionee 78,086 431,933 McIntosh 4B 109,609 219,636 ABB CE & CQ Inc. -- CQE Coal Processing for Clean Fuels 10,864 21,746 43,125 105,700 Western SynCoal ENCOAL 45,332 90,664 Custom Coals On hold 37,994 87,386 Air Products -- LPMEOH Coal Tech [_ Industrial Applications 40984 5,983 17,800 92,708 213,700 Passamaquoddy Bethlehem Steel 31,824 194,302 CPICOR 149,469 1,065,805 - Preaward Ee - Design and Construction Zz - Operation and Reporting (1) - completion scheduled for July 2007 Program Update 1999 3-7 Cost-Sharing A characteristic feature of the CCT Program is the cooperative funding agreement between the participant and the federal government referred to as cost-sharing. This cost-sharing approach, as imple- mented in the CCT Program, was introduced in 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. General concepts and requirements of the cost-sharing principle as applied to the CCT Program include the following elements: * The federal government may not finance more than 50 percent of the total costs of a project; * Cost-sharing by the project participants is required throughout the project (design, construction, and operation); * The federal government may share in project cost growth (within the scope of work defined in the original cooperative agreement) up to 25 percent of the originally negotiated government share of the project; + The participant’s cost-sharing contribution must occur as project expenses are incurred and cannot be offset or delayed based on prospective project revenues, proceeds, or royalties; and + Investment in existing facilities, equipment, or previously expended R&D funds are not allowed for the purpose of cost-sharing. As previously discussed, Exhibit 3-1 summarizes the cost-sharing status by subprogram and by applica- tion category for the 40 active or completed projects. 3-8 Program Update 1999 In the advanced electric power generation category, which accounts for 53 percent of total project costs, participants are contributing 61 percent of the funds. Cost-sharing by participants for environmental control devices, coal processing for clean fuels, and industrial applications categories is 58 percent, 56 percent, and 85 percent, respectively. For the overall program, participants are contributing 66 percent of the total funding, or $1.7 billion more than the federal government. Recovery of Government Outlays (Recoupment) The policy objective of DOE is to recover an amount up to the government’s financial contribution to each project. Participants are required to submit a plan outlining a proposed schedule for recovering the government’s financial contribution. The solicitations have featured different sets of recoupment rules. Under the first solicitation, CCT-I, repayment was derived from revenue streams that include net revenue from operation of the demonstration plant beyond the demonstration phase and the commercial sale, lease, manufacture, licensing, or use of the demonstrated technology. In CCT-II, repayment was limited to revenues realized from the future commer- cialization of the demonstrated technology. The government’s share would be 2 percent of gross equipment sales and 3 percent of the royalties realized on the technology subsequent to the demonstration. The CCT-III repayment formula was adjusted to 0.5 percent of equipment sales and 5 percent of royalties. Limited grace periods were allowed on a project-by-project basis. A waiver on repayment may be sought from the Secretary of Energy if the project participant determines that a competitive disadvantage would result in either the domestic or international marketplace. The recoupment provisions for CCT-IV and CCT-V were identical to those in CCT-III. As of September 30, 1999, five projects have made repayments to the federal government: Nucla CFB Demonstration Project (Tri-State Generation and Transmission Association, Inc.); Full-Scale Demon- stration of Low-NO, Cell Burner Retrofit (The Bab- cock & Wilcox Company); Development of the Coal Quality Expert™ (ABB Combustion Engineering, Inc. and CQ Inc.); 10-MWe Demonstration of Gas Suspen- sion Absorption (AirPol, Inc.); and the Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.). In September 1997, the CCT Program office issued a report entitled Recoupment Lessons Learned — Clean Coal Technology Demonstration Program. The report: (1) reviewed the lessons learned on “recoupment” during the implementation of the CCT Program; (2) addressed recommended actions set forth in General Accounting Office (GAO) Report RCED-92-17, GAO Report RCED-96-141, and Inspector General Audit Report IG-0391 relative to “recoupment”; and (3) provided input into DOE deliberations on “recoupment” policy. 4. CCT Program Accomplishments Introduction The CCT Program’s continued success is exempli- fied as demonstrated by the following demonstrations completing operation in Fiscal Year 1999: * Blast Furnace Granular-Coal Injection System Demonstration, and * Micronized Coal Reburning Demonstration for NO, Control. These completed projects, along with the other 38 active and completed projects, are producing a wealth of knowledge on clean coal technologies. The success of the CCT Program ultimately will be measured by the contribution the technologies make to the resolution of energy, economic, and environmen- tal issues. These contributions can only be achieved if the public and private sectors understand that clean coal technologies can increase the efficiency of energy use and enhance environmental quality at costs that are competitive with alternative energy options. The CCT Program has continued efforts to define and understand the potential domestic and international markets for clean coal technologies. Domestically, this activity requires a continuing dialogue with electric utility executives, public utility commissioners, and financial institutions. Also required are analyses of the effect that regional electric capacity requirements, environmental compliance strategies, and electric utility restructuring have on the demand for clean coal technologies. Internationally, activities include partici- pating in international conferences and workshops, furnishing information on clean coal technologies, and providing technical support to trade agencies, trade missions, and financial organizations. Throughout the 1999 fiscal year, the CCT Pro- gram staff participated in over 16 domestic and inter- national events involving users and vendors of clean coal technologies, regulators, financiers, environmen- tal groups, and other public and private institutions. Included was the Seventh Clean Coal Technology Conference, held in Knoxville, Tennessee and attend- ed by 230 participants from 12 countries. Four issues of the Clean Coal Today newsletter were published in the same period, along with the fourth annual edition of the Clean Coal Today Index, which cross-references all articles published in the newsletter. A new series of reports, 12-page Project Performance Summary documents, were issued for 10 of the completed CCT Program projects. Also, four Clean Coal Technology topical reports were issued during the fiscal year. The DOE also continued expanded coverage of the pro- gram by publishing the Clean Coal Technology Dem- onstration Program: Update 1998, and the mid-year update of project fact sheets, Clean Coal Technology Demonstration Program: Project Fact Sheets 1999. Subsequent to the end of fiscal year 1999, but prior to publication of this report, the cooperative agreement for two demonstration projects expired— NOXSO Corporation and Custom Coals International are in bankruptcy and were not able to restructure and continue work under the CCT Program. Information on NOXSO Corporation’s Commercial Demonstration of the NOXSO SO,/NO, Removal Flue Gas Cleanup System and Custom Coals International’s Self-Scrub- bing Coal™: An Integrated Approach projects are included in this report because there is data that read- COAL TECHNOLOGY & w tang Techookgen fo he cee ‘Onis Emasons from Coal Program Update 1999 4-1 ers may find beneficial. Furthermore, this report is based on the status as of September 30, 1999 and the expiration of these cooperative agreements occurred after that date. These two projects will not be included in future reports. Marketplace Commitment Reflecting CCT Program commercialization goals, the majority of the projects involve demonstrations at commercial scale, providing the opportunity for the participants to continue operation of the demonstrated technologies as part of their strategy to comply with the CAAA. With government serving as a risk-sharing partner, industry funding has been leveraged to: * Create jobs, * Improve the environment, * Reduce the cost of compliance with environ- mental regulations, * Reduce the cost of electricity generation, v SO, control technologies: AirPol (left), CT-121 (center), and LIFAC (right). 4-2 Program Update 1999 * Improve power generation efficiencies, and * Position U.S.-based industry to export innova- tive services and equipment. Reflecting the marketplace commitment, the CCT projects are organized within four major product lines —environmental control devices, advanced electric power generation, coal processing for clean fuels, and industrial applications. Thus, the CCT Program can be viewed from a market perspective. This section of the Program Update highlights some of the program and project accomplishments to date along with commer- cialization successes by market sector. Environmental Control Devices All but 2 of the 19 environmental control device projects have now completed operations. The complet- ed demonstrations proved commercial viability of a suite of cost-effective SO, and NO, control options for the full range of coal-fired boiler types. Risk was significantly mitigated in successfully applying the technologies commercially because of the extensive databases and attendant predictive models developed through the demonstrations. Also, projects were lever- aged to provide input in formulating NO, control requirements under the CAAA and to evaluate the impact of emerging issues, such as air toxics, on the existing boiler population and control options. Exten- sive air toxics testing was performed in conjunction with 10 of the environmental control projects. To a great extent, the technologies were retained for com- mercial service at the demonstration sites and many technology suppliers have realized commercial sales. SO, Control Technologies. All five SO, control technology demonstrations have completed operations, evaluating three basic approaches to address the di- verse coal-fired boiler population: (1) sorbent injec- tion, (2) gas-suspension absorption, and (3) advanced flue gas desulfurization. * Two low-capital cost sorbent injection systems, sponsored by LIFAC—North America and Bechtel Corporation, demonstrated SO, capture efficiencies in the range of 50 to 70 percent. These systems hold particular promise for the older, smaller units, particularly those with space constraints. + A moderate-capital cost gas-suspension- absorption system, sponsored by AirPol, Inc., demonstrated SO, capture efficiencies in the range of 60 to 90 percent. The system has particular applicability to the small- to mid- range units with some space limitations. * Two advanced flue gas desulfurization (AFGD) systems, sponsored by Pure Air on the Lake, L.P. and Southern Company Services, having somewhat higher capital costs than the other approaches, demonstrated SO, capture efficiencies in the range of 90 to 95 percent. These systems are primarily applicable to the larger, newer units that have space available. The AFGD projects redefined the state-of-the-art in scrubber technology by proving that a single absorb- er module of advanced design could process large volumes of flue gas and provide the required availabili- ty and reliability. This single module design, without the usual spares, combined with integration of func- tions within the absorber module and use of high throughput designs, nearly halved capital cost and space requirements. The AFGD testing also estab- lished that wallboard-grade gypsum could be produced in lieu of solid waste; wastewater discharge could be eliminated; and, by mitigating corrosion, fiberglass- reinforced-plastic fabrication could eliminate process steps (e.g., prequenching for chloride removal and flue gas reheat). The AFGD demonstration by Southern Company Services using Chiyoda CT-121 showed that the system could significantly enhance particulate control. Pure Air on the Lake, L.P., introduced an innovative busi- ness concept whereby the company builds, owns, and operates scrubbers as a contracted service to a utility. The arrangement relieves utilities of the burden of ownership and operation. Commercialization successes to date for the SO, control technologies are summarized in Exhibit 4-1. NO, Control Technology. Six of the seven NO, control technology demonstrations have successfully completed operations. Testing was conducted on the four major boiler types (wall-fired, tangentially-fired, cyclone-fired, and cell-burner boilers), representing over 90 percent of the coal-fired boiler population; however, applicability extends to all boiler types. Typically, NO, emission reductions achieved for the various approaches were: * Low-NO, burners and OFA: 45 to 68 percent + Reburning systems: 50 to 67 percent SNCR systems: 30 to 50 percent SCR systems: 80 to 90+ percent Advanced controls: 10 to 15 percent The database developed during Southern Company Services’ evaluation of NO, control on wall-fired and tangentially-fired boilers at Plant Smith and Plant Hammond, respectively, was used by EPA in formulat- ing NO, provisions under the CAAA. ABB Combus- tion Engineering’s LNCFS™ proved effective in demonstration for tangentially-fired boilers and real- ized commercial acceptance, as did Foster Wheeler’s Controlled Flow/Split Flame and Babcock & Wilcox’s DRB-XCL* low-NO, burners for wall-fired boilers. The Babcock & Wilcox Company’s low-NO, cell burner, LNCB", provided an effective low-cost plug-in NO, control system for cell-burner boilers, which are known for their inherently high NO, emissions. Integration of neural-network systems into digital boiler controls, such as the Generic NO, Control Intelligence System (GNOCIS) installed at Plant Hammond, demonstrated effective optimization of parameters for NO. control and boiler performance under load-following operations. The Babcock & Wilcox Company’s coal reburning technology proved not only to be an effective way to control NO, on cyclone boilers, but a means to avoid derating cyclone boilers when switching to low-sulfur, low-rank western coals. Energy and Environmental Research Corporation’s use of gas reburning, applica- ble to all boiler types, introduced an alternative to SCR for high NO, emission reduction particularly when used with low-NO_ burners. In another project, comparative analyses were conducted on a range of SCR catalysts operated on high-sulfur U.S. coals, providing needed insight on the environmental and economic performance potential of SCR. Other SCR systems and selective non-catalytic reduction (SNCR) systems were demonstrated in conjunction with combined SO,/NO, control technologies. Commercialization successes to date for the NO, control technologies are summarized in Exhibit 4-2. Combined SO,/NO, Control Technologies. Six of the seven combined SO,/NO, control technol- ogy demonstrations have successfully completed operations. The demonstrations evaluated a multi- plicity of complementary and synergistic control methods to achieve cost-effective SO, and NO, emissions reductions. SNOX™, a catalytic process developed by Haldor Topsoe a/s, consistently achieved 95 and 94 percent SO, and NO, control, respectively. The process also demonstrated excellent particulate control, while producing a salable by-product in lieu of solid waste. In a project sponsored by Public Service Company of Colorado, complementary use of low-NO, burners with SNCR resulted in NO, emission reductions of greater than 80 percent. SNCR interacted synergistical- ly with sorbent injection to reduce ammonia slip and NO, emissions. Sodium-based sorbent injection achieved 70 percent SO, removal at high sorbent utilization rates. New York State Electric & Gas Corporation (NYSEG) evaluated an advanced flue gas desulfuriza- tion system, the S-H-U scrubber process. The S-H-U process, an advanced formic acid-enhanced wet lime- stone scrubbing process, demonstrated a 98 percent SO, capture efficiency. In conjunction with the S-H-U- process, NYSEG also evaluated micronized coal as a reburn fuel using close-coupled reburning techniques and deep staged combustion incorporated into ABB Combustion Engineering, Inc.’s LNCFS™ burners. Program Update 1999 4-3 Exhibit 4-1 Commercial Successes—SO, Control Technology Project Commercial Use 10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC-—North America) Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) Sold domestically and internationally. GSA market entry was significantly enhanced with the sale of a 50-MWe unit, worth $10 million, to the city of Hamilton, Ohio subsidized by the Ohio Coal Development Office. A sale worth $1.3 million has been made to the U.S. Army for hazardous waste disposal. A GSA system has been sold to a Swedish iron ore sinter plant. Sales to Taiwan, Indonesia, and India have a combined value of $20 million. Furthermore, Taiwan contracted for technical assistance and proprietary equipment valued at $1.0 million. No sales reported. CZD/FGD can be used to retrofit existing plants or for new installations at a cost of about one-tenth that of a commercial wet scrubber. Sold domestically and internationally. There are 10 full-scale LIFAC units in operation in Canada, China, Finland, Russia, and the United States. The LIFAC system at Richmond Power & Light is the first to be applied to a power plant using high-sulfur (2.0-2.9%) coal. The LIFAC system has been retained for commercial use by Richmond Power & Light at Whitewater Valley Station, Unit No. 2. No sales reported. The AFGD continues in commercial service at Northern Indiana Public Service Company’s Bailly Generating Station. Gypsum produced by the PowerChip® process is being sold commercially. Sold internationally. Plant Yates continues to operate with the CT-121 scrubber as an integral part of the site’s CAAA compliance strategy. Since the CCT Program demonstration, over 8,200 MWe equivalent of CT-121 FGD capacity has been sold to 16 customers in 7 countries. 4-4. Program Update 1999 Exhibit 4-2 Commercial Successes—NO_ Control Technology Project Commercial Use Micronized Coal Reburning Demonstration for NO, Control (New York State Electric & Gas Corporation) Demonstration of Coal Reburning for Cyclone Boiler NO, Control (The Babcock & Wilcox Company) Full-Scale Demonstration of Low-NO, Cell Burner Retrofit (The Babcock & Wilcox Company) Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler (Energy and Environmental Research Corporation) Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers (Southern Company Services, Inc.) 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers (Southern Company Services, Inc.) Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) No sales reported. Technology retained for commercial use at Kodak Power Plant. No sales reported. Technology retained for commercial use at Wisconsin Power and Light Company’s Nelson Dewy Station. Sold domestically. Dayton Power & Light has retained the LNCB® for use in commercial service. Seven commercial contracts have been awarded for 172 burners, valued at $27 million. The LNCB" technology has already been installed on more than 4,900 MWe of capacity. Sold domestically and internationally. Public Service Company of Colorado, the host utility, decided to retain the low-NO, burners and the gas-reburning system for immediate use; however, a restoration was required to remove the flue gas recirculation system. Energy and Environmental Research Corporation has been awarded two contracts to provide gas reburning systems for cyclone coal-fired boilers: TVA’s Allen Unit 1 (a 330-MWe unit) as well as Baltimore Gas & Electric’s C. P. Crane Units | and 2 (similar 200-MWe units). The technology is also installed at Ladyzkin State Power Station in Ladyzkin, Ukraine. No sales reported. SCR has realized commercial acceptance abroad. The demonstration tests established SCR as a viable U.S. compliance option and aided utilities in developing the most cost-effective site-specific applications of SCR. Sold domestically and internationally. LNCFS™ has been retained at the host site for commercial use. ABB Combustion Engineering has modified 116 tangentially-fired boilers, representing over 25,000 MWe, with LNCFS™ and derivative TFS 2000™ burners. Sold domestically and internationally. The host has retained the technologies for commercial use. Foster Wheeler has equipped 86 boilers (51 domestic and 35 international) with low-NO, burner technology—a total of 1,800 burners representing over 30,000 MWe capacity valued at $35 million. Twenty-six commercial installations of GNOCIS, the associated Al control system, are underway or planned. This represents over 12,000 MWe of capacity. In a strict sense, this project has not been completed; it has been extended to apply GNOCIS to other pieces of plant equipment, which may increase its commercial potential. Program Update 1999 4-5 DHR Technologies supplied a plant optimization control system known as the Plant Emission Optimiza- tion Advisor or PEOA™, which has been sold to a number of users in the power industry. The Babcock & Wilcox Company’s SO,-NO -Rox Box™, an integration of a newly developed high- temperature fabric-filter bag (for baghouse installa- tions) with SCR and sorbent injection, proved to be an easily installed, highly efficient control system for SO,, NO,, and particulates. Typical performance was 80 percent SO, removal, 90 percent NO, removal, and 99.9 percent particulate removal. Limestone injection multistage burner (LIMB) and coolside demonstrations proved that sorbent injection methods could achieve up to 70 percent SO, reduction. The Babcock & Wilcox DRB-XCL" advanced low- NO, burners reduced NO, emissions by 45 percent. Energy and Environmental Research Corporation’s demonstration of gas reburning and sorbent injection showed that: (1) NO, reductions greater than 60 percent could be achieved with only 13 percent natural gas heat input, and (2) SO, removal of over 55 percent could be achieved by using special sorbents. NOXSO Corporation’s demonstration of a dry, regenerable flue gas cleanup process is designed to remove 98 percent of the SO, and 75 percent of the NO, from a coal-fired boiler’s flue gas. Commercialization successes to date for the combined SO, and NO, control technologies are summarized in Exhibit 4-3. Advanced Electric Power Generation Pollution control was the priority early in the CCT Program. This program emphasis included technolo- gies that could effectively repower aging plants faced with the need to both control emissions and respond to 4-6 Program Update 1999 growing power demands. Repowering is an important option because existing power generation sites have significant value and warrant investment because the infrastructure is in place and siting new plants repre- sents a major undertaking. This recognition led to award early on of three key repowering projects—two ACEB projects and a PFBC project. As the CCT Program unfolded, a number of energy and environmental issues combined to change the emphasis toward seeking highly-efficient, very low- emission power generation technologies for both repowering and new power generation. This emphasis was deemed essential to enable coal to fulfill its pro- jected contribution to the nation’s energy mix well into the 21" century. Environmental issues included a growing concern over greenhouse gas emissions, capping of SO, emissions, increasing attention to NO, in ozone nonattainment areas, and recognizing fine particulate emissions (respirable particulates) as a particular health threat. These issues prompted follow- on projects in PFBC, initiation of projects in IGCC, and projects in advanced combustion and heat engines. Fluidized-Bed Combustion. The Tri-State Generation and Transmission Association, Inc.’s Nucla Station repowering project provided the database and operating experience requisite to making ACFB a commercial technology option at utility scale. At 110 MWe, the Nucla ACFB unit was more than 40 percent larger than any other ACFB at that time. Up to 95 percent SO, removal was achieved during the 15,700 hours of demonstration, and NO, emissions averaged a very low 0.18 Ib/10° Btu. The thrust of this effort was to fully evaluate the environmental, operational, and economic performance of ACFB. As a result, the most comprehensive database on ACFB technology avail- able to date was developed. Based on this knowledge, commercial units were offered and built. While the Nucla project established commercial acceptance of ACFB at moderate utility capacities, a second CCT demonstration project, located in Jackson- ville, Florida, is carrying on where Nucla left off. JEA will build a 300-MWe plant, which will have the distinction of being the largest ACFB in the world, as well as one of the cleanest. Today, every major U.S. boiler manufacturer offers an ACFB in its product line. There are now more than 120 fluidized-bed combustion boilers of varying capacities operating in the United States, and the technology has made significant market penetration abroad. Through the Ohio Power Company’s repowering of the Tidd Plant (70 MWe), the potential of PFBC as a highly efficient, very low pollutant emission technol- ogy was established and the foundation was laid for commercialization. The PFBC system constructed was the first utility-scale system in the United States. Efforts were focused on fully evaluating the perfor- mance potential. Over 11,444 hours of operation, the technology successfully demonstrated SO, removal efficiencies up to 95 percent with very high sorbent utilization (calcium-to-sulfur molar ratio of 1.5), and NO, emissions in the range of 0.15 to 0.33 1b/10° Btu. The Tidd Plant PFBC was one of the first genera- tion 70-MWe P200 units installed in the early 1990s. Others were built and operated in Sweden, Spain, and Japan. ABB Carbon, the technology supplier, uses a “bubbling” fluidized-bed design, which is character- ized by low fluidization velocities and use of an in-bed heat exchanger. The first 360-MWe P800 PFBC is being built in Japan and is scheduled for operation in 1999. And, a “second generation” P200 PFBC with freeboard-firing is operating in Cottbus, Germany. A number of other ABB Carbon PFBC projects are under Exhibit 4-3 Commercial Successes—Combined SO,/NO, Control Technology Project Commercial Use SNOX™ Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) LIMB Demonstration Project Extension and Coolside Demonstration (McDermott Technology, Inc.) SO,-NO,-Rox Box™ Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) Integrated Dry NO,/SO, Emissions Control System (Public Service Company of Colorado) International use. The host utility, Ohio Edison, is retaining the SNOX™ technology as a permanent part of the pollution control system at Niles Station to help meet its overall SO, and NO, reduction goals. Commercial SNOX™ plants are also operating in Denmark and Sicily. In Denmark, a 305-MWe plant has operated since August 1991. The boiler at this plant burns coals from various suppliers around the world, including the United States; the coals contain 0.5-3.0% sulfur. The plant in Sicily, in operation since March 1991, has a capacity of about 30 MWe and fires petroleum coke. Sold domestically and internationally. LIMB has been sold to an independent power plant in Canada. Babcock & Wilcox has signed contracts for 124 units for DRB-XCL” low-NO, burners, representing 2,428 burners for 31,467 MWe of capacity. The low-NO, burners have an estimated value of $240 million. No sales reported. Commercialization of the technology is expected to develop with an initial larger scale application equivalent to 50-100 MWe. The focus of marketing efforts is being tailored to match the specific needs of potential industrial, utility, and independent power producers for both retrofit and new plant construction. SNRB™ is a flexible technology that can be tailored to maximize control of SO,, NO,, particulate, or combined emissions to meet current performance requirements while providing flexibility to address future needs. No sales reported. Illinois Power has retained the gas-reburning system and City Water, Light & Power has retained the full technology for commercial use. (See Evaluation of Gas Reburning and Low-NO, Burner on a Wall-Fired Boiler project for a complete understanding of commercial success of the technology.) Sold domestically. Six modules of DHR Technologies’ Plant Emissions Optimization Advisor, with an estimated value of $210,000, have been sold. A U.S. company, SHN, has been established to market the S-H-U scrubber. SHN is pursuing an advanced flue gas desulfurization bid for a Pennsylvania site. ABB Combustion Engineering has modified 116 units representing over 25,000 MWe with LNCFS™ or its derivative TFS 2000™. Sold domestically. The technology was retained by Public Service Company of Colorado for commercial service at its Arapahoe Station. The Babcock & Wilcox DRB-XCL” burner that was demonstrated has realized sales of 2,428 burners, representing 31,467 MWe. The burners are valued at $240 million. Program Update 1999 4-7 consideration in China, South Korea, the United King- dom, Italy, and Israel. Two ongoing interrelated projects, McIntosh 4A and McIntosh 4B, will demonstrate PCFB at utility scale. PCFB uses a higher fluidization velocity than bubbling-bed systems, which entrains the bed material. Bed material is separated from the flue gas by cyclones and recirculated to the combustor. The economizer, which captures heat from the flue gas, is downstream of the cyclones. McIntosh 4A will evaluate a 137-MWe first generation PCFB configuration using Foster Wheel- er technology. McIntosh 4B will demonstrate a second generation system by integrating a small coal gasifier (pyrolyzer) to fuel the gas turbine “topping cycle,” thereby adding 103 MWe capacity. The second genera- tion PCFB has the potential to significantly improve the efficiency of pressurized fluidized-bed systems by increasing power generation from the gas turbine, which is more efficient than the steam bottom cycle. Integrated Gasification Combined-Cycle. Three of four IGCC projects are in operation under the CCT Program. They represent a diversity of gasifier types, cleanup systems, and applications. PSI Energy’s 262- MWe Wabash River Coal Gasification Repowering Project began operation in November 1995 and contin- ues in its fourth year of commercial service. The utility dispatches the unit over other coal-fired units because of its high efficiency. The unit, which is the world’s largest single train IGCC, has operated on coal for over 12,400 hours and processed more than one million tons of coal. The unit has achieved monthly production levels of one trillion Btus of syngas on several occasions. The 250-MWe Tampa Electric Integrated Gasifi- cation Combined-Cycle Project began commercial operation in September 1996 and continues to accumu- late run time. The gasifier has accumulated over 4-8 Program Update 1999 15,000 hours of operation and produced over 3,500,000 MWh of electricity on syngas. Tests have included evaluation of various coal types on system performance. The Sierra Pacific Power Company (SPPC) continues to make progress on its IGCC system. The 99-MWe Pifion Pine IGCC Power Project at SPPC’s Tracy Station began operation on natural gas in No- vember 1996. The GE Frame 6FA, the first of its kind in the world, performed well. The plant has undergone shakedown, and design modifications have been made. The system has achieved steady state gasifier operation for short periods through September 1999, but contin- ues to experience difficulty with sustained operations. The Kentucky Pioneer Energy IGCC Demonstra- tion Project, which is in the design stage, will offer yet another gasifier design and include the testing of a fuel cell operated on syngas from the coal gasifier. This will provide valuable data for design of an integrated gasification fuel cell (IGFC) system. IGFC has the potential to achieve efficiencies greater than 60 percent. Commercial configurations resulting from the current IGCC and PFBC demonstrations will typically have efficiencies at least 20 percent greater than conventional coal-fired systems (with like CO, emis- sion reductions), remove 95 to 99 percent of the SO,, reduce NO, emissions to levels well within NSPS, reduce particulate emissions by one-third to one-tenth that currently allowed under the CAAA, and produce salable by-products from solid residues as opposed to waste. Advanced Combustion/Heat Engines. Two projects are demonstrating advanced combustion/heat engine technology. The Healy Clean Coal Project is demonstrating TRW’s entrained (slagging) combustor combined with Babcock & Wilcox’s spray-dryer absorber using sorbent recycle. Operations com- menced in January 1998. Results from environmental compliance testing showed very low emissions—0.26 Ib/10° Btu for NO,, 0.01 1b/10° Btu for SO,, and 0.0047 Ib/10° Btu for particulates. Permit levels are 0.35 Ib/10° Btu for NO,, 0.086 Ib/10° Btu for SO,, and 0.03 1b/10° Btu for particulates because of the plant’s proximity to a national park. NSPS allows 1.2 Ib/10° Btu for SO,. The Clean Coal Diesel Demonstration Project is evaluating a heavy duty diesel engine operating on a low-rank coal-water fuel. The demonstration plant is expected to achieve 41 percent efficiency and future commercial designs are expected to reach 48 percent Y= Three IGCC plants are in operation: Tampa Electric (top), Pifion Pine (middle), and Wabash River (bottom). efficiency. As of September 1999, the checkout of the diesel engine was in progress. Commercialization successes for the advanced electric power generation systems to date are summa- rized in Exhibit 4-4. Coal Processing for Clean Fuels Two of five projects in the coal processing for clean fuels category completed operations and submit- ted final reports. Projects in this category include physical and chemical processes that can be used to transform the abundant U.S. coal reserves into eco- nomic, environmentally compliant solid and liquid fuels and feedstocks. The solid products from coal processing are largely designed to be readily transport- able; high in energy density; and low in sulfur, ash, and moisture. The liquid products are designed to be suitable as transportation and stationary power genera- tion fuels, or as chemical feedstocks. Both solid and liquid products, and the processes that produce them, have substantial market potential both domestically and internationally. The ENCOAL and Western SynCoal LLC projects are breaking down the barrier to using the nation’s vast low-sulfur but low-energy-density western coal re- sources. The resultant fuels have particular application domestically for CAAA compliance and internationally for Pacific Rim energy markets. ENCOAL/’s solid fuel product has an energy density of about 11,000 Btu per pound, and the sulfur content averages 0.36 percent. ENCOAL’s liquid fuel product can substitute for No. 6 fuel oil or serve as a chemical feedstock. During the demonstration, over 83,500 tons of solid fuel was shipped to seven custom- ers in six states, as well as 203 tank cars of liquid product to eight customers in seven states. Five com- mercial feasibility studies have been completed—two for Indonesia, one for Russia, and two for U.S. projects. Permitting of a 15,000 metric ton/day com- mercial plant in Wyoming is nearly complete. The Western SynCoal LLC project is demonstrat- ing another route to producing high-quality fuel from low-rank coals. The advanced coal conversion process (ACCP) upgrades low-rank coal to produce a low- sulfur (as low as 0.3 percent sulfur) SynCoal" product having a heating value of about 12,000 Btu per pound. The Western SynCoal LLC has signed a letter of agreement to supply fuel to Montana Power’s 330- MWe Colstrip Unit No. 2. Five other agreements have been signed. The advanced physical coal-cleaning technology developed by Custom Coals International uses high- sulfur bituminous feedstocks to produce two types of compliance coal—Carefree Coal™ and Self-Scrubbing Coal™, Air Products Liquid Phase Conversion Company, L.P., is demonstrating the LPMEOH™ process to produce methanol from coal-derived synthesis gas. The LPMEOH™ process has been developed to enhance integrated gasification combined-cycle power generation facilities by coproducing a clean-burning storable liquid fuel from coal-derived synthesis gas. The production of dimethyl ether (DME) as a mixed coproduct with methanol will also be demonstrated. Methanol and DME may be used as a low-SO,, low- NO, alternative liquid fuel, a feedstock for the synthe- sis of chemicals, or as a new oxygenate fuel additive. Since start-up, the LPMEOH™ demonstration unit has produced over 43 million gallons of methanol, all of which was accepted by Eastman Chemical Company for use in downstream chemical processing. Since restart of the unit with fresh catalyst in December 1997, availability of the unit has been greater than 99 percent and catalyst activity decline has approached 0.4 percent/day. ABB Combustion Engineering, Inc. and CQ Inc. developed PC-based software, CQE™, to assist utilities in assessing the environmental and operational perfor- mance of their systems for the available range of coal fuels to determine the least-cost option. The CQE™ software has been distributed to over 35 utility members of EPRI and is being marketed commercially worldwide. Two U.S. utilities also have been licensed to use copies of the CQE™ stand-alone Acid Rain Advisor. A = The LPMEOH™ demonstration unit at Eastman Chemical Company’s vast chemicals-from-coal complex in Kingsport, TN. Program Update 1999 4-9 Exhibit 4-4 Commercial Successes—Advanced Electric Power Generation Project Commercial Use Tidd PFBC Demonstration Project (The Ohio Power Company) Nucla CFB Demonstration Project (Tri-State Generation and Transmission Association, Inc.) Tampa Electric Integrated Gasification Combined-Cycle Project (Tampa Electric Company) Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) Pifion Pine IGCC Power Project (Sierra Pacific Power Company) Healy Clean Coal Project (Alaska Industrial Development and Export Authority) Sold internationally. Success of the project has led Babcock & Wilcox to invest in the technology and acquire domestic licensing rights. Commercial ventures abroad include the following: — Vartan in Sweden is operating two P200 units to produce 135 MWe and 224 MWt; — Escatron in Spain is operating one P200 unit producing 80 MWe; — Wakamatsu in Japan is operating one P200 unit to produce 71 MWe; — Cottbus in Germany is operating one P200 unit to produce 71 MWe and 40 MWt; — Karita in Japan operates one P800 unit to produce 360 MWe; and — Other projects under construction are in China, South Korea, U.K., and Israel. Sold domestically and internationally. Today, every major boiler manufacturer offers an ACFB system in its product line. Since the demonstration, commercial sales of 29 units greater than 100 MWe have been realized, representing 6.2 gigawatts of capacity valued at nearly $6 billion. Sold domestically and internationally. First greenfield IGCC unit in commercial service. Texaco, Inc., and ASEA Brown Boveri signed an agreement forming an alliance to market IGCC technology in Europe. There are currently 10 IGCC projects using a Texaco gasifier that are either planned or under construction. No sales reported. First repowered IGCC unit in commercial service and is the world’s largest single train IGCC in commercial service. Preferentially dispatched over other coal-fired units is PSI Energy’s system because of high efficiency. No sales reported. Unit in initial operation preparatory to commercial service. No sales reported. TRW offering licensing of combustor worldwide (China agreement in place). Commercial operation tests are ongoing. 4-10 Program Update 1999 Commercialization successes for the coal pro- cessing technologies to date are summarized in Exhibit 4-5. Industrial Applications The CCT Program is addressing the environmental issues and barriers associated with coal use in industri- al applications. Three of five projects have completed operations in this area. Historically, production of steel has been depen- dent upon coke. Coke making, however, is an inher- ently large producer of hazardous air pollutants. Also, cement production often relies on coal fuel because production costs are largely driven by fuel costs. Because of its low stable price, coal is an attractive substitute for oil and gas in industrial boilers, but concerns over increased SO, and NO, emissions and boiler tube fouling have impeded coal use. Under a project with Bethlehem Steel Corporation, British Steel’s blast furnace granular-coal injection (BFGCI) technology demonstrated that 40 percent of the coke can be replaced with coal injected directly into a blast furnace where emissions from coal combus- tion are effectively controlled in the process. CPICOR™ Management Company L.L.C. is in the design stage of demonstrating direct iron ore reduction and smelting of iron oxides using coal in lieu of coke. This would eliminate the need for coke. The Passamaquoddy Tribe successfully demon- strated a unique recovery scrubber that uses cement kiln dust, otherwise disposed of as waste, to remove 90 percent of the SO,, produce fertilizer and distilled water, and convert the kiln dust to feedstock with no waste generated. Coal Tech Corporation moved closer to commer- cializing a combustor for industrial boilers that slags the ash in the combustor to prevent boiler tube fouling, controls NO, (70 to 80 percent reduction) through staged combustion, and controls SO, (90 percent) with sorbent injection. ThermoChem, Inc. has completed restructuring of its project and will be demonstrating a multiple resonance tube pulse combustor design. Commercialization successes for the industrial applications technologies to date are summarized in Exhibit 4-6. Awards The projects in the CCT Program have won numerous awards from news, professional, and non- profit organizations. A listing of those awards is contained in Exhibit 4-7. Market Communications— Outreach Outreach has been a hallmark of the CCT Program since its inception. It was recognized early on that commercialization of technology requires acceptance by a range of interests including: technology users; equipment manufactures; suppliers and users of raw materials and products; financial institutions and insurance underwriters; government policy makers, legislators, and regulators; and public interest groups. Requisite to acceptance is an outreach program to provide these customers and stakeholders with both program and project information and to seek, on a continuing basis, feedback on program direction and information requirements. An ongoing outreach program has aggressively sought to disseminate key information to the full range of customers and stake- A The Burns Harbor Plant was the site of the BFGCI demonstration. holders and to obtain feedback on changing needs. The effort has recognized the need to highlight envi- ronmental, operational, and economic performance characteristics of clean coal technologies and to rede- sign information packages as customers and stakehold- ers, and their respective needs, change with the market. Specific objectives of the outreach program include the following: + Achieving public and government awareness of advanced coal-using technologies as viable energy options; * Providing potential technology users, both foreign and domestic, with information that is timely and relevant to their decision making process; + Providing policy makers, legislators, and regulators with information about the advan- tages of clean coal technologies; * Convincing financial institutions and insurance underwriters that clean coal technologies are viable options; and Program Update 1999 4-11 Exhibit 4-5 Commercial Successes—Coal Processing for Clean Fuels Project Commercial Use Development of the Coal Quality Expert™ (ABB Combustion Engineering, Inc. and CQ, Inc.) ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process (Air Products Liquid Phase Conversion Company, L.P.) Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) Sold domestically and internationally. The Electric Power Research Institute (EPRI) owns the software and distributes it to EPRI members for their use. CQ Inc. and Black and Veatch have signed commercialization agreements that give both companies nonexclusive worldwide rights to sell user licenses and offer consulting services that include use of CQE". More than 35 U.S. utilities and one U.K. utility have received CQE” through EPRI membership. Two modules of the Acid Rain Advisor valued at $6,000 have been sold. It is estimated that CQE” saves U.S. utilities about $26 million annually. Domestic and international sales pending. In order to determine the viability of potential LFC” plants, five detailed commercial feasibility studies—two Indonesian, one Russian, and two U.S. projects—have been completed. Permitting of a 15,000 metric-ton/day commercial plant in Wyoming is nearly complete. No sales reported. Nominal 80,000 gallon/day methanol production being used by Eastman Chemical Company. No sales reported. Total sales of SynCoal” product exceed 1.5 million tons. Six long-term agreements are in place to purchase the product. One domestic and five international projects have been investigated. Western SynCoal LLC has a joint marketing agreement with Ube Industries of Japan providing Ube non-exclusive marketing rights outside of the United States. Ube is pursuing several projects in Asia. Western SynCoal is also discussing a potential marketing and development agreement with a U.S. engineering firm. Exhibit 4-6 Commercial Successes—Industrial Applications Project Commercial Use Project (Bethlehem Steel Corporation) and Ash Control (Coal Tech Corporation) Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) No sales reported. The scrubber became a permanent part of the cement plant at the end of the demonstration. A feasibility study has been completed for a Taiwanese cement plant. Blast Furnace Granular-Coal Injection System Demonstration Domestic sale. British Steel’s Blast Furnace Granular-Coal Injection System was sold and installed on a facility owned by United States Steel Corporation. Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, No sales reported. While the combustor is not yet fully ready for sale with commercial guarantees, it is believed to have commercial potential. Follow-on work to the CCT Program demonstration was undertaken, which has brought the technology close to commercial introduction. 4-12 Program Update 1999 Exhibit 4-7 Award-Winning CCT Projects Project and Participant Award Full-Scale Demonstration of Low-NO, Cell Burner Retrofit (The Babcock & Wilcox Company) Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler; Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Demonstration of Innovative Applications of Technol- ogy for the CT-121 FGD Process (Southern Company Services, Inc.) Tidd PFBC Demonstration Project (The Ohio Power Company) Tampa Electric Integrated Gasification Combined- Cycle Project (Tampa Electric Company) Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) Development of the Coal Quality Expert™ (ABB Combustion Engineering, Inc. and CQ Inc.) 1994 R&D 100 Award presented by R&D magazine to the U.S. Department of Energy for development of the low-NO, cell burner. 1997 J. Deanne Sensenbaugh Award presented by the Air and Waste Management Association to the U.S. Department of Energy, Gas Research Institute, and U.S. Environmental Protection Agency for the development and commercialization of gas-reburning technology. 1993 Powerplant Award presented by Power magazine to Northern Indiana Public Service Company’s Bailly Generating Station. 1992 Outstanding Engineering Achievement Award presented by the National Society of Professional Engineers. 1995 Design Award presented by the Society of Plastics Industries in recognition of the mist eliminator. 1994 Powerplant Award presented by Power magazine to Georgia Power’s Plant Yates. Co-recipient was the U.S. Department of Energy. 1994 Outstanding Achievement Award presented by the Georgia Chapter of the Air and Waste Management Association. 1993 Environmental Award presented by the Georgia Chamber of Commerce. 1992 National Energy Resource Organization award for demonstration of energy-efficient technology. 1991 Powerplant Award presented by Power magazine to American Electric Power Company’s Tidd project. Co-recipient was The Babcock & Wilcox Company. 1997 Powerplant Award presented by Power magazine to Tampa Electric’s Polk Power Station. 1996 Association of Builders and Contractors Award presented to Tampa Electric for quality of construction. 1993 Ecological Society of America Corporate Award presented to Tampa Electric for its innovative siting process. 1993 Timer Powers Conflict Resolution Award presented to Tampa Electric by the state of Florida for the innovative siting process. 1991 Florida Audubon Society Corporate Award presented to Tampa Electric for the innovative siting process. 1996 Powerplant Award presented by Power magazine to CINergy Corp./PSI Energy, Inc. 1996 Engineering Excellence Award presented to Sargent & Lundy upon winning the 1996 American Consulting Engi- neers Council competition. In 1996 recognized by then Secretary of Energy Hazel O’Leary and EPRI President Richard Balzhiser as the best of nine DOE/EPRI cost-shared utility R&D projects under the Sustainable Electric Partnership Program. Program Update 1999 4-13 * Providing forums and opportunities for feed- back on program direction and information requirements. Information Sources A portfolio of publications and information access media exist and are being improved upon as program and marketplace events unfold. Information is current- ly distributed to over 4,000 customers and stakeholders, 275 of which are CCT project participants. The fol- lowing provides a brief synopsis of the publications and information transfer mechanisms currently in place: Clean Coal Technology Demonstration Program: Program Update provides an annual summary of program and project progress, accomplishments, and financial status along with an historical backdrop and program role relative to current policy. Clean Coal Technology Demonstration Program: Project Fact Sheets provides a mid-year update on each project. Clean Coal Technology Conference Proceedings serves as an update on issues impacting the program, feedback on program information requirements, and a periodic snapshot of how each of the active projects is progressing with some degree of technical depth. Clean Coal Today newsletter offers the readership a quarterly look at the program, highlighting key events, updating project status, reporting on related issues, and listing the latest publications and upcoming events. Project Performance Summary documents provide a 12-page synopsis of completed projects, highlighting operational, environmental, and economic performance. Clean Coal Technology Topical Reports capture projects at critical junctures and highlight particular 4-14 Program Update 1999 technological advantages, project plans, and expected outcomes. National Technical Information Service (NTIS) serves as the federal government’s central source for the sale of scientific, technical, engineering, and related business information produced by or for the U.S. government. NTIS has most of CCT Program techni- cal reports. CCT Program Bibliography of Publications, Papers, and Presentations periodically updates the key materials available on the technologies demonstrated under the CCT Program. The Investment Pays Off periodically takes a market-based view of the success of the CCT Program by virtue of commercial sales and relevance of ongoing activities to projected market need. CCT Program—Lessons Learned documents the lessons learned in soliciting, selecting, and awarding projects and implementing the program. CCT Compendium provides an electronic database incorporating the CCT Program publications that can be accessed on the Internet (http://www. lanl.gov/ projects/cctc/). Exhibits provide a means through graphics, pho- tos, broadcast videos, and interactive videos to convey program messages at a variety of forums, and serve as focal points for distribution of literature and discussion of the program and information needs. There are currently four exhibits of varying sizes and complexity that are updated and modified, as necessary, to convey the appropriate message for specific forums. Fossil Energy Home Page provides the primary Internet gateway to extensive information on DOE’s Fossil Energy Program and to relevant World Wide Web links (http://www.fe.doe.gov). Exhibit4-8 summarizes how the above publications can be obtained and information sources can be accessed. A The CCT Compendium is a new source of information on the CCT Program Publications Issued in FY1999 The following publications were issued in fiscal year 1999 by the CCT Program. Similar publications can be expected in fiscal year 2000. * Seventh Clean Coal Technology Conference— 21" Century Coal Utilization: Prospects for Economic Viability, Global Prosperity, and a Cleaner Environment, Volume | Policy Paper, and Volume 2 Technical Papers * Clean Coal Technology Demonstration Program: Program Update 1998 * Clean Coal Technology Demonstration Program: Project Fact Sheets 1999 * Clean Coal Today: Winter 1998, Spring 1999, Summer 1999, Fall 1999 * Clean Coal Today Index * Project Performance Summary—10-MWe Demonstration of Gas Suspension Absorption * Project Performance Summary—180-MWe . Demonstration of Advanced Tangentially-Fired Combustion Techniques for the Reduction of NO, Emissions * Project Performance Summary—ABB Environ- mental Systems SNOX™ Flue Gas Cleaning Demonstration Project * Project Performance Summary—Advanced Flue Gas Desulfurization Demonstration Project * Project Performance Summary—Cement Kiln Flue Gas Recovery Scrubber™ * Project Performance Summary—Demonstra- tion of Coal Reburning for Cyclone Boiler NO, Control * Project Performance Summary—Full-Scale Demonstration of Low-NO, Cell Burner® Retrofit Project Performance Summary—Nucla ACFB Demonstration Project Project Performance Summary—SO -NO -Rox Box™ Flue Gas Cleanup Demonstration Project Project Performance Summary—Tidd PFBC Demonstration Project Topical Report—Advanced Technologies for the Control of Sulfur Dioxide Emissions from Coal-Fired Boilers Topical Report—Commercial-Scale Demon- stration of the Liquid Phase Methanol (LPMEOH™) Process Topical Report—Reburning Technologies for the Control of Nitrogen Oxides from Coal- Fired Boilers Exhibit 4-8 How to Obtain Updated CCT Program Information Media Description and Action Clean Coal Today Fossil Energy Home Page CCT Compendium CCT Program Update and other publications National Technical Information Service (NTIS) Subscription to quarterly newsletter—Send name and address to U.S. Department of Energy, FE-24, Washington, DC 20585. Primary gateway to extensive information on DOE’s Fossil Energy Program and to relevant Web links—On the Internet, access http://www. fe.doe.gov and use menu and/or search options. On the Internet, access http://www.lanl.gov/projects/ccte/. Send name and address to U.S. Department of Energy, FE-20, Washington, DC 20585. U.S. Department of Commerce, 5285 Port Royal Road, Springfield, VA 22161. * Topical Report—Technologies for the Com- bined control of Sulfur Dioxide and Nitrogen Oxides Emissions from Coal-Fired Boilers Information Access The Department of Energy continued to expand its website to provide information on federal fossil energy programs and serve as a gateway to other related information throughout the United States and the world. Once into the DOE website, users can obtain general information and follow links to increasingly detailed information, ultimately accessing specific data on individual projects and facilities. Hyperlinks allow users to move seamlessly between headquarters and field sites. Users can also access technical abstracts and reports maintained by DOE’s Office of Scientific and Technical Information at Oak Ridge, Tennessee. The gateways link to more than a hundred energy- related websites operated by private companies, trade associations, and other agencies worldwide. Furthermore, the Fossil Energy International Activities site on the World Wide Web has been expanded with the addition of new country pages in the Western Hemisphere region (Dominican Republic, El Salvador, and Haiti). Many of the existing country pages have also been upgraded, with new hyperlinks to business- or energy-related information sources. An innovation at the Fossil Energy International Activities website is a series of newly created Country Energy Overviews. Each overview, individualized for a particular country, includes a status summary of that country’s energy infrastructure, energy and environ- mental policies, and privatization efforts. Fifteen country pages are now available. The Uniform Re- source Locator (URL) for the Fossil Energy Interna- tional main page is http://www.fe.doe.gov/internation- Program Update 1999 4-15 al and can be accessed via the “International” hyperlink in the Fossil Energy Home Page (http://www. fe.doe.gov). In February 1998, DOE established a new informa- tion resource on the Internet. The Clean Coal Technolo- gy Compendium, sponsored by the Office of Fossil Energy and the National Energy Technology Laboratory (NETL), is dedicated to making the maximum use of information derived from the CCT Program. The com- pendium is designed to emphasize ease of use, and contains a broad collection of different types of data and information, making it applicable to the needs of both managers and engineers. For example, one can access the latest Clean Coal Technology Demonstration Pro- gram: Program Update and Topical Reports published periodically on individual CCT projects. The CCT Compendium is accessible via the Internet at http://www.lanl.gov/projects/ctc/. Information Dissemination and Feedback A number of mechanisms are used to disseminate program information to customers and stakeholders and obtain feedback from them on specific issues, program direction, and information requirements. The following provides a brief outline of the mechanisms. Public Meetings were routinely held over the course of the acquisition phase of the CCT Program to solicit input on procurement actions. Subsequently, project participants have been holding open houses for the public, providing tours of demonstration facilities, and publicizing projects through groundbreaking and dedication ceremonies. Executive Seminars involve program officials meeting with key industry officials at their places of business to facilitate discussion. Discussions seek to: obtain a better understanding of the dynamics of the decision making process for adopting new power 4-16 Program Update 1999 generating technologies, determine how the program could best support the process and achieve a positive outcome, and gain insights on the future direction of the power industry. Over 50 meetings have been held since 1992 with influential leaders in the utility, inde- pendent power, regulatory, and financial communities. Stakeholder Meetings bring together key stake- holder organizations for the purpose of coordinating programs, where appropriate, and discussing pertinent issues and implementation strategies to address the issues and outreach needs. Such stakeholder organiza- tions include the Electric Power Research Institute (EPRI), Gas Research Institute (GRI), Coal Utilization Research Council, Center for Energy & Economic Development (CEED), Council of Industrial Boiler Owners (CIBO), Clean Coal Technology Coalition, and National Mining Association (NMA). Conferences and Workshops bring together target- ed audiences to review and discuss topics of interest, document discussions and findings, and provide recom- mendations, as appropriate. Trade Missions are a subset of these and differ only in that the thrust is international in character with the purpose of promot- ing the export of U.S. services and technology. The outreach program has participated in over 200 technical conferences, workshops, and trade missions since 1991, Seventh Clean Coal Technology Conference On June 21-24, 1999, over 230 people from 12 countries gathered in Knoxville, Tennessee for the Seventh Clean Coal Technology Conference. Cospon- sors included CEED, NMA, EPRI, CIBO, and DOE. Air Products and Chemicals, Inc. and the Eastman Chemical Company hosted the conference and a site visit to the Commercial-Scale Demonstration of the Liquid Phase Methanol Process being demonstrated at the Eastman Chemical Company facility in Kingsport, Tennessee. The following is a summary of the papers and presentations at the conference. The views of the various speakers do not necessarily reflect the views of DOE. Opening Remarks. The DOE Assistant Secretary for Fossil Energy provided opening remarks, reflecting on how far coal technologies have come and on the promise for the future. The Assistant Secretary noted that progress in power system technology has far surpassed projections made in the 1970s, when only magnetohydrodynamics was expected to approach 50 percent efficiency. Now gasification, fluidized-bed combustion, and advanced gas turbine technologies provide a clear path to the 50 percent efficiency thresh- old. Moreover, only 20 years ago environmental control was more art than science. Through the CCT Program, advances in science-based gas cleanup technology have saved more than $40 billion in com- pliance costs. In looking to the future, the Assistant Secretary shared his vision of virtually pollution-free coal-based power systems, producing multiple products at 60 percent generating efficiency and reaching 85 percent thermal efficiency. He reflected on the fact that this vision approached that of the first Assistant Secretary for Fossil Energy over 20 years ago—“the day pollu- tion would no longer be associated with the word coal.” Keynote Speakers. Keynote speakers from both the coal industry and the utility industry addressed the conference participants. Coal Industry Perspective. The coal industry, as represented by the President of NMA, perceives the challenge for the power industry as maintaining low costs and reliability of service in meeting the projected 1.7 trillion kilowatt-hour of new electric power capaci- ty needed by 2020 (almost twice the growth of the last 20 years). To meet this challenge, the coal industry supports programs such as DOE’s CCT Program, Vision 21, and Industries of the Future. These pro- grams are seen as providing coal and power producers the means to adequately perform. NMA views perfor- mance as the key to countering public policy unfavor- able to coal. For example, coal provided the needed response to the last major energy build-up between 1982 and now (885 billion kilowatt-hours), this despite predictions of coal’s demise and a nuclear power takeover of electricity generation. As a result, the United States has far lower energy costs than other industrialized nations, which American households have come to expect and American industry relies on for competitiveness. The suggested lessons to be learned are that fuel diversity must be maintained to adjust to changing circumstances and that performance determines outcomes. VY One of four clean coal technology exhibits, shown here, was used at the Seventh CCT Conference to convey a technical message. A Seventh CCT Conference attendees toured the LPMEOH™ demonstration project. Utility Perspective. The Chairman and President of American Electric Power (AEP) suggested that there are three givens regarding the future of coal in electric- ity generation: (1) powering the future will require a diversified fuel mix; (2) coal will continue in a promi- nent role in that mix; and (3) the advancement of clean coal and related technologies will be more critical than ever in going forward. There also is a need to change the public perception of coal, including speaking on the issues affecting coal, including: (1) air quality issues of urban and regional smog, or ozone, associated with nitrogen oxide emissions; (2) fine particulates, acid rain, mercury, and regional haze, primarily associated with sulfur dioxide emissions; and (3) the climate change questions of greenhouse gases, principally carbon dioxide, and global warming. AEP sees the need to deflect environ- mental concerns with a technological response to preserve coal as the primary source for electric power generation, but also recognizes the need to protect all other options as well. This includes continuing development of renew- able energy sources, expanding use of natural gas, and keeping the nuclear option open. The AEP speaker noted that nuclear generation has ceased to be a source for new capacity, with no new plants having been ordered since 1973 (that weren’t canceled). Preserving the existing 100 nuclear plants is seen as a challenge. Further observations were that many hydroelectric plants may not be relicensed; despite support by utilities, renewables cannot begin to replace fossil fuels; and natural gas can not take the strain of replacing nuclear and coal generating capacity. The message conveyed was that fuel diversity is essential to preserving our nation’s security and economic stability, which could be compromised if the public’s negative perception of coal leads to public policy limiting coal use. Issues. The issues identified at the conference include: (1) Deploying Clean Coal Technologies; (2) Global Community Responsibility—Role of Technolo- gy and Project Developers, Financiers, Consumers, and Governments; and (3) Coal in Tomorrow’s Energy Fleet—Pressures and Responsibilities. Deploying Clean Coal Technologies. For both developed and developing countries, coal is projected to be a key component in the energy supplies. Howev- er, current coal technologies can not satisfy the energy security and environmental goals of society and deliver affordable energy. On the other hand, power system technologies emerging from the CCT Program offer the economic, environmental, and operational perfor- mance potential needed to maintain coal in the fuel supply, meet environmental goals, and keep energy affordable. The challenge is in achieving widespread deployment of these clean coal technologies. Program Update 1999 4-17 A The CCT Conference gives stakeholders the opportunity to offer feedback to CCT Program management. The President’s Council of Advisors on Science and Technology (PCAST) identified deficiencies in the process of moving technologies from the demonstration phase to widespread deployment. So despite success- ful demonstrations under the CCT Program, work remains to move the technologies into the marketplace. PCAST suggests that a “buydown” phase must ensue during which the incremental cost between the new technology and conventional technology is covered. During this buydown phase, cost and risk are reduced, as the technology is replicated and design and manu- facturing methods are refined and standardized. PCAST concluded that a public entity is required to provide the policy and financial support for the buy- down. The status of clean coal technologies vis-a-vis the need for buydown was examined. Clean coal technolo- gies currently have efficiencies higher than convention- al pulverized coal units but lower than natural gas combined-cycle units. Clean coal technology capital costs, upon technology maturity, will be 20 to 25 percent lower than pulverized coal, but 50 percent higher than natural gas combined-cycle. Integrated gasification combined-cycle and pressurized fluidized- 4-18 — Program Update 1999 bed combustion technologies are cost-competitive with pulverized coal now, but not natural gas combined- cycle. The IGCC and PFBC technologies could be competitive with natural gas combined-cycle in 2010, if fuel prices follow projected trends. The fuel price differential between coal and natural gas must be greater than $2.00/10° Btu for clean coal technologies to be competitive with natural gas combined-cycle. Barriers identified for coal technologies by devel- opers include capital cost, restructuring of the electric utility industry, and construction lead time. The capital risk of clean coal technologies is estimated at twice that of natural gas combined-cycle, which also means higher taxes, insurance, and financing costs. The electric utility industry favors less capital-intensive projects to maximize short term profits. Longer con- struction schedules for coal plants means slower response to market signals for new capacity and greater risk from more stringent environmental regulations. From an environmental perspective, clean coal technologies provide high levels of pollution control and efficiency, but still fall short of a natural gas combined-cycle plant. Carbon sequestration represents. a leveling factor for clean coal technologies in carbon control, but much work remains to be done. Achieving widespread clean coal technology deployment and the benefits derived from having fuel diversity will require financial support for the developer. The preferred financial mechanisms identified were incentives, rather than grants or subsidies. Moreover, incentives must address higher capital costs, higher operating cost and risk, and start-up risk. These risks can be addressed by investment tax credits, production tax credits, and risk pools, respectively. A further stipulation was that such an incentives program would qualify technologies on the basis of increased efficiency over time and would be limited in scope and duration. Global Community Responsibility—Role of Tech- nology and Project Developers, Financiers, Consumers, and Governments. Speakers on this subject suggested that there is a global community responsibility to put energy resources and the advanced technology needed to use those resources in the hands of the two billion people in the world who currently lack access to these basic building blocks of modern society. Furthermore, by applying advanced technology, the global energy resources are more than sufficient to support economic growth without compromising the environment. Speakers observed that little progress has been made in addressing the one-third of the six billion world population lacking access to commercial forms of energy. Most of these people live in developing countries where 90 percent of the population growth is occurring, and will increase by another two billion people by 2020. This will contribute to an estimated 50 percent increase in global energy consumption over the next two decades. New partnerships and economic models are needed to address the problem, such as: ¢ Restructuring and commercialization of energy enterprises; ¢ Sharing information through energy partner- ships; * Establishing transparent regulatory, pricing, and procurement policies; * Investing in technology development reflecting a long-term, global view; and * Providing tools for developing countries to solve their own problems. Coal must play a role in meeting energy demands because coal is the predominant indigenous resource for many of the developing economies. But bringing in advanced coal technology faces the hurdles of least cost, risk averse decision makers, the “NIMBY” (not in my back yard) syndrome, and unrealistic expectations for renewables. Speakers pointed out that developing countries will realize a 290 percent growth in energy requirement relative to 1990. The associated financial requirement is an estimated $5 trillion, which developing countries can not meet along with other infrastructure needs. Strong recommendations were made by several speak- ers that industrialized countries share their prosperity in targeted efforts to bring energy to rural impover- ished regions of the world. If not, poverty will contin- ue for two billion people today and possibly four billion people by 2020 (half the projected world popu- lation). The World Bank Group has adopted a number of policies to help bring modern forms of energy to the two billion people who currently do not have access. Vv The Secretary of Energy addresses conference attendees and takes questions from the audience. These policies include insisting upon reforms in the energy sector to support competition, private sector investment, and sound regulation of the sector. Poli- cies also promote energy efficiency both on the supply- and demand-side and integrate energy pricing and environmental policies. The World Bank Group will undertake upstream “Energy-Environmental Reviews” to set priorities for action across the whole energy chain. For coal, the World Bank launched the Clean Coal Initiative, which addresses the entire coal chain from mining to end-use, and in parallel, seeks sector reforms and least-cost environmental control options. The view from the commercial debt financing market, as presented at the conference, does not look promising for new coal technologies. The debt financ- ing market does not see its role as accepting the risk associated with new technologies. Corporate entities or governments are expected to shoulder the risk until such time as the technology reaches commercial matu- rity. Furthermore, computer models used by power rate consultants include the choice of building a coal plant instead of a natural gas plant to supply future capacity needs. These computer models invariably choose natural gas plants because of lower capital cost and permitting ease. The operating assumption is, therefore, that new generation over the next 15 to 25 years will be supplied overwhelmingly by simple-cycle or combined-cycle natural gas-fired plants. Coal in Tomorrow's Energy Fleet—Pressures and Responsibilities. According to views expressed at the conference on this issue, the energy business is chang- ing. In this new energy business environment, research and development is not considered one of the factors driving corporate growth and value. The energy trading and marketing function will drive actions in the energy business. Traders primarily think in financial and commodity market terms. This includes conducting daily assessments of “value at risk” and viewing gener- ating assets as “real options.” The growing use of options analysis for corporate decision making, or real options, represents a decision making revolution, according to Business Week. Re- search and development investments and technologies are considered real options because investment today can generate the possibility of new opportunities tomorrow. Also, technologies such as clean non-natural gas fossil fuel systems are options that can hedge against price risk and price volatility. For example, a plant that could produce syngas from coal (or other low-cost fuel) at an “out-of-the-money” price of $4.00/ 10° Btu, theoretically has value today as a hedge against natural gas exposure. Indicative values might be $500—750/kW based on selling forward 15 years and the degree of price volatility. The question then becomes whether the syngas plant can be built for $500-750/kWe. From a real options perspective, “high tech” may not have as much option value as “low tech,” and integrated systems may lose option value versus non- integrated systems. “Enabling technologies” with the highest market value are those that allow rapid installa- tion, are not location sensitive, and are deployed in a modular fashion. The Department of Energy presented its view of tomorrow’s energy fleet, which is embodied in the agency’s Vision 21 Program. Vision 21 is a govern- ment/industry/academia cost-shared partnership to develop the technology basis for integrated energy plants that will result in the deployment of ultra-clean plants that produce electricity and “opportunity” products. Opportunity products could include clean liquid transportation fuels, steam, high-value chemicals, Program Update 1999 4-19 synthesis gas, and hydrogen. Fuels include coal and natural gas in combination with other resources such as biomass, municipal waste, and petroleum coke. Vision 21 goals are to effectively remove environmental constraints as an issue for fossil fuel use by reducing pollutant emissions to near-zero, increasing efficiency to reduce greenhouse gas emissions by up to 50 per- cent, and enabling sequestration to achieve net zero CO, emissions. Specific efficiency targets cited were 60 percent (HHV) for coal-based systems, 75 percent (LHV) for natural gas-based systems, 85 percent efficiency (HHYV) in combined heat and power applications, and 75 percent fuels utilization efficiency in fuels produc- tion. To achieve these targets, enabling technologies have been identified that provide the foundation for the subsystems, or modules, that form the building blocks of a Vision 21 plant. These enabling technologies include: oxygen and hydrogen separation membranes, high-temperature heat exchangers, fuel flexible gasifi- cation, hot gas cleanup, advanced combustion, fuel flexible turbines, fuel cells, and advanced catalysts. Supporting technologies that crosscut enabling technol- ogy efforts include: materials, advanced computational modeling (virtual demonstration), advanced controls and sensors, advanced environmental controls, and advanced manufacturing and modularization. A number of system examples, such as a gasifica- tion/gas turbine/fuel cell hybrid cycle, were presented to illustrate that efficiency targets were feasible. The Department of Energy representative pointed out that, in the evolution of these systems, there will be spinoff technologies commercialized. The sequential commer- cialization and integration of technologies will mitigate the risk and cost of module development. 4-20 Program Update 1999 Industry representatives identified several targets for coal-based generation technologies by 2020 along with several cross-cutting enabling technologies. The targets are capital costs of $800/kW, efficiencies of 50- 60 percent, SO, removal of 99 percent, NO, emissions of 0.05 Ib/10° Btu, and 100 percent waste utilization. The enabling technologies are high temperature/high pressure filters, advanced combustion turbines, high temperature steam cycle materials, and hazardous air pollutant controls. With these capabilities, it is project- ed that coal can account for 20 percent of primary energy in a balanced 2050 portfolio. Looking to the future, it was also pointed out that carbon capture and sequestration offer an opportunity to remove the single greatest concern over continued reliance on fossil fuels—global climate change. To scope the challenge, results were presented from detailed cost analyses on CO, capture followed by a discussion of the challenges involved in developing secure storage reservoirs. In addressing CO, capture costs, analysts selected three representative power generation technologies: IGCC, natural gas combined-cycle, and pulverized coal-fired combustion. Analysis showed the incremen- tal cost of electricity for CO, capture to be 1.1 to 1.7 cents/kWh for IGCC; 1.9 to 2.1 cents/kWh for natural gas combined-cycle; and 2.3 to 3.1 cents/kWh for pulverized coal. This suggests that coal-based IGCC could compete with natural gas in a greenhouse gas constrained world. The CO, capture costs presented represent com- mercial technology today. The potential to reduce these costs is great, e.g., improving thermal efficiency of the basic plant, or reducing the energy requirement for CO, capture by improving separation technologies. The sequestration options identified along with capaci- ty estimates are listed below. For reference, the total annual worldwide anthropogenic carbon emissions are about 7 gigatons of carbon (Gtc). Reservoir Capacity (Gte/yr) Ocean 1,000s Deep Saline Formations 100s to 1,000s Oil & Gas Reservoirs 100s Unminable Coal Seams 10s to 100s Terrestrial Biosphere 10s to 100s Utilization 0.1 Geologic sequestration issues identified include uncertainties in storage volumes available, long-term integrity of the storage, and costs of CO, transport and storage. Storage integrity is both a performance and public safety issue. Ocean sequestration issues include sequestration efficiency for the proposed methods and environmental impacts. Conferences and Workshops Held in FY1999 Third Meeting of Energy Ministers from the Asia Pacific Economic Cooperation, and Sixth Annual Technical Seminar. In October 1998, the Energy Ministers from the Asia Pacific Economic Cooperation (APEC) held their third meeting in Okina- wa, Japan to consider policy issues, many of which are important to vendors of clean coal technologies and other fossil energy technologies in foreign markets. The U.S. Secretary of Energy led the U.S. delegation. APEC was formed in 1989 to address issues of grow- ing regional interdependence. Members include 18 countries bordering the Pacific Ocean with a combined Gross Domestic Product of $13 trillion in 1995. Con- current with the Ministers’ meeting, the FE-led Experts Group on Clean Fossil Energy (part of the APEC’s Energy Working Group (EWG)) hosted its Sixth Annual Technical Seminar with a focus on practical coal, gas, and oil use technologies for developing economies. Coal is of extreme importance to the Pacific Rim because of large indigenous supplies. In fact, an APEC-sponsored workshop in February 1998 in Honolulu, Hawaii, “Energy Security: Fuel Supplies for the Power Industry,” concluded that coal would contin- ue to play a significant role in the region’s fuel mix. Natural gas was seen as desirable due to its environ- mental benefits and potential availability, while oil use in the region’s power sector was not expected to grow. Implications of the Asian financial crisis pervaded the October 1998 discussions. Ministers agreed that energy can play a key role in economic recovery. Investment in infrastructure, a key goal, could induce a multiplier effect. In spite of the economic downturn and projected slower growth in demand, the region’s demand for energy is expected to outpace energy production by a wide margin. The Asia Pacific Energy Resource Centre, established by the EWG, presented the Ministers with a new forecast that predicts total primary energy demand in the region will increase 41 percent over the period 1995-2010. This growth will require large amounts of investment capital. To reduce dependence on imported oil, APEC nations are inter- ested in diversifying energy supplies, developing financing for power infrastructure, and encouraging energy efficiency. The Ministers who met at Okinawa endorsed a work program on environmentally sound infrastructure for all energy sources. Concerns are not only for environmen- tally sensitive siting, but maintenance practices and employee training. The goal of the work program is to provide an impetus to the application of predictable, transparent, and consistent energy policy practices. Policy recommendations to accelerate investment in natural gas infrastructure (part of the Natural Gas Initiative launched at the first meeting of the Ministers in Edmonton, Canada) were also approved. Recom- mendations were included in the report, “Accelerating Investment in Natural Gas Supplies, Infrastructure and Trading Networks in the APEC Region.” The Initia- tive stresses not only the building of pipelines, but addressing regulatory and cross-border issues that may act as impediments. Reducing costs through cooperation in energy standards was another endorsement by the Ministers that has potential bearing on coal and the standards for equipment to be sold. APEC members’ economies have been surveyed to determine the range of testing practices and procedures and the degree of mutual recognition of facility test results. The standards notification provision endorsed by the Ministers would increase transparency and consistency in energy effi- cient product standards within APEC. To improve energy efficiency, Ministers also endorsed a voluntary “pledge and review” system. Energy efficiency means not only “green” technologies, but better use of con- ventional fossil fuel resources. Although APEC is an organization of government representatives, the Energy Ministers have directed the EWG to expeditiously engage with businesses on measures to improve investor confidence in APEC nations’ energy sectors. The EWG has established a Business Network comprising two private sector energy executives from each member economy. The Ministers instructed the EWG to work with industry to implement the principles in the “APEC Manual of Best Practice Principles for IPPs,” which was endorsed at Edmonton. Trends in Development in Mining and Power Production From the Point of View of Future Applications of Clean Coal Technologies. In No- vember 1998, two FE representatives were invited to chair panels and present papers at the conference Trends in Development in Mining and Power Produc- tion From the Point of View of Future Applications of Clean Coal Technologies, held in Kocise, Slovakia. The conference was hosted by the Slovak Academy of Sciences Institute of Geotechnics (Slovak Academy), with broad sponsorship by the mining and power industry in Slovakia. The Office of Fossil Energy, under a Science and Technology grant from the U.S. Department of State, has collaborated with the Slovak Academy on research focusing on the region’s high- ash, high-arsenic coals, specifically the process of cleaning the coal using the concept of triboelectrostatic charging. This process avoids expensive dewatering. Slovakian brown coal is currently used for power generation in pulverized coal plants with few environ- mental controls, and is also used extensively for district heating and rural home stoves. Coal supplies are dwindling and expected to last for only another 20 years. The conference, attended by some 75 key repre- sentatives from the academic, mining, power, district heating, chemical, steel, and environmental sectors in Central and Eastern Europe, addressed various techni- cal issues common to this area, particularly cost issues of environmental compliance and power production. Currently, 60 percent of Slovakia’s power comes from older nuclear plants, 30 percent from coal plants, and 10 percent from natural gas. Slovakia is under pressure to shut down the Chernobyl-type nuclear plants and must find replacement capacity, or it will have to import electricity. There is hesitancy to become overly dependent on natural gas, and strong interest (including Program Update 1999 4-21 employment in the mining sector) in continuing to use indigenous coal supplies while they last. In general, the country seeks a better balance between nuclear-, coal-, and natural gas-fired power plants. Coal-fired plants in Slovakia are slowly being converted to circulating fluidized-bed combustion boilers. A definite market exists for cleaner coal technologies for district heating, small combined heat and power plants, and for chemical raw materials. Conference participants were most interested in the presentation on CCT projects, particularly the Nucla and JEA atmospheric fluidized-bed combustion projects, Pifion Pine IGCC, Liquid Phase Methanol, and granulated coal injection as demonstrated by the Bethlehem Steel project, because these technologies could have application throughout all of Central and Eastern Europe. In all, Slovakia and other countries in the region have been keenly watching coal R&D advances, and seek opportunities to deploy new tech- nologies applicable to their reserves. International Seminar on Combustion Technol- ogies for Clean Energy Generation. In December 1998, representatives from FE participated in the International Seminar on Combustion Technologies for Clean Energy Generation held in Mexico City. This activity was part of the U.S.-Mexican Bilateral Agreement for Energy Cooperation, under the Hemi- sphere Energy Initiative’s Clean Energy Working Group program. Mexican sponsors included the National Commission on Energy Savings (CONAE) and the Institute of Electric Research. An important part of the seminar was FE’s presen- tation entitled “Fluidized-Bed Combustion Repowering for Mexico,” which was delivered to more than 100 Mexican energy officials. Presently, 60-70 percent of Mexico’s power is generated from fossil fuels, 80-90 4-22 Program Update 1999 percent of which comes from oil, with the rest generated from natural gas and two pulverized-coal plants that burn high-ash (approximately 50 percent ash) Mexican coal. A new coal plant being built will run on imported, low-sulfur coal. Ap- proximately 17 percent of Mexico’s power is generated by hydroelectric plants and the remaining national demand is met by two 650-MW nuclear units, supplemented by some geothermal, wind, and solar units. The presentation focused on four fluidized-bed combustion (FBC) repowering options for Mexico’s aging oil-fired power boilers. These options included (1) replacement of existing units with atmospheric fluidized-bed boilers, (2) conversion of existing units into fluidized-bed boilers using compact separator designs, and replacement of existing boilers with either (3) first generation PFBC or (4) second generation (topped) PFBC units. The fuel flexibility of FBC was stressed. Particular attention was devoted to petroleum coke in recognition of Mexico’s global position as a major oil producing nation. The audience asked a number of questions concerning burning of petroleum coke in the United States. Examples such as the NIBSCO 300-MW petroleum coke-fired plant in Lake Charles, Louisiana were discussed. The NIBSCO plant is completing its sixth year of successful opera- tion, which includes the sale of all produced ash by- product for use in highway construction. The Office of Fossil Energy’s final technical presentation was on the Vision 21 program. Audience questions focused on the continuing use of fossil fuels, especially coal, into the next millennium. The Mexican audience was surprised to see that such focused and Titernationsl emia on Combustinn te, 7 clean energy generat A Representatives from the U.S. DOE participated in the “International Seminar on Combustion Technologies for Clean Energy Generation,” held in Mexico City in December 1998. careful attention is still being given to fossil-based power technologies. The FE presenter indicated that, with the exception of nuclear, which is politically not an option in many countries, fossil is the only viable energy source to meet the bulk of the world’s demand for power. The presenter stressed the need to develop and deploy technologies that will allow use of fossil fuels as cleanly and efficiently as possible. On December 4, 1998, a follow-up meeting was held at the offices of Mexico’s Secretariat of Energy, which generated further questions about FBC opera- tions. CONAE indicated that it would take the lead to promote future FBC activities between FE and Mexico. 13" Annual U.S./Japan Joint Technical Work- shop on Coal Technology. A successful /3” Annual U.S./Japan Joint Technical Workshop on Coal Tech- nology was held in early March 1999 at the Rocky Gap Lodge near Cumberland, Maryland. Sixty-six work- shop participants exchanged R&D project information relating to advanced clean coal technologies, coal liquefaction, liquefaction materials, and surface gasifi- cation. Japan has recently been pursuing coal utiliza- tion R&D quite aggressively, and has been involved in direct liquefaction research. The Director of the National Energy Technology Laboratory (NETL), who is also Co-Chair of the U.S.- Japan Coordinating Committee on Coal Energy R&D, spoke on the globalization and deregulation forces behind energy supply decisions, and summarized FE’s current R&D focus. The NETL Director led a U.S. team of government representatives, members of research organizations, and the private sector. The representative of the Japanese Ministry of International Trade and Industry (MITI), and Co-Chair of the committee, led a Japanese delegation of 24 scientists and engineers from utilities, research organizations, industry associations, and energy companies. The technical exchange was open and frank. A representative of MITI’s Agency of Natural Resources and Energy, spoke on Japanese coal utilization policy, noting that Japan imports 80 percent of its total energy feedstock and 99.7 percent of its oil (with oil account- ing for 54 percent of Japan’s total energy consump- tion). Japan is the second largest foreign consumer of U.S. coal. Only five percent of coal used in Japan is domestic. Other industrialized nations (e.g., Germany, France, and Italy) import over 95 percent of their oil. The U.S. depends on imports for 20 percent of its total energy and 50.7 percent of its oil, with oil comprising 38 percent of total U.S. energy consumption. Workshop participants noted that ample, low cost, stable coal supplies worldwide support a measure of diversification and economic safety for both industrial- ized and developing countries, making the develop- ment of clean, efficient, coal utilization technologies an imperative for the future. DOE presentations intro- duced the Vision 21 research program the Department has proposed for coal-based power and fuel systems in the next century. McDermott International, Inc. sum- marized low-NO, burners, as well as emissions control studies for particulate matter and trace elements. The A NETL Director addresses attendees at 13" Annual U.S./ Japan Joint Technical Workshop on Coal Technology. Energy & Environmental Research Center described an advanced hybrid particulate collector, American Electric Power gave a presentation on the 600-MWe demonstration of selective non-catalytic reduction to be conducted at its Cardinal Unit 1, and Air Products & Chemicals presented an overview of advanced integra- tion concepts for oxygen plants and gas turbines in gasification/IGCC facilities using ion transport mem- branes. Japan’s New Energy Development Organization described the EAGLE (Energy Application for Gas, Liquids, and Electricity) integrated coal gasification, molten carbonate fuel cell combined-cycle plant that is moving toward pilot-scale demonstration in the 2000 to 2002 time frame. About 90 percent of the project is funded by the Japanese government. Japan’s Electric Power Development Company presented recent results from the 71-MWe Wakamatsu PFBC plant, as well as from recent PDU testing of an advanced PFBC pro- cess. Representatives from Tokyo Electric discussed results obtained from a 200 ton/day IGCC pilot plant at Nakoso, using a process design by Mitsubishi Heavy Industries. Following the workshop, representatives from the Japanese delegation toured NETL in-house laboratory facilities and the Tampa Electric IGCC project. Prospects for Cleaner Fossil Fuels Systems in Sustainable Development: Communicating Their Strategic Value in the Euro-Asian Region. The U.S. Department of Energy was among the sponsors of the highly successful conference, Prospects for Cleaner Fossil Fuels Systems in Sustainable Development: Communicating Their Strategic Value in the Euro- Asian Region, held in Ankara, Turkey in May 1999. Other conference sponsors included the World Energy Council (WEC), as well as the WEC Turkish National Committee and the Regional Working Group for Cooperation in the Field of Energy, the U.S. Agency for International Development (USAID), and the U.S. Energy Association. The highlight of the conference was an appearance by the President of Turkey. In his remarks, the Turkish President emphasized the role of Turkey as a major energy distribution point as well as energy consumer. Turkey’s average energy demand is predicted to grow 8-10 percent per year through 2010. A $280 billion investment program is planned for the energy sector over the next 30 years. While the most timely energy issue is planned commencement of the Baku-Ceyhan oil pipeline and the Trans-Caspian natural gas pipeline, Turkish energy officials highlighted the importance of coal. Turkey has 8 billion tons of lignite (brown coal) reserves as well as some “hard” coal. Sixty percent of coal produced is used for generating electricity, with the remainder going for industry and household use. By 2020, lignite and hard coal are expected to repre- sent 20 percent of installed capacity. DOE’s Office of Fossil Energy showed a strong presence at the conference, with the FE Assistant Program Update 1999 4-23 Secretary as the Keynote Speaker, the Director of the Office of Import & Export (within the Office of Coal and Power Systems (OC&PS)) serving as President of the first day’s session, and the Director of the Office of Power Systems (within OC&PS) making a presentation on the role of fossil energy and Vision 21. The Assis- tant Secretary spoke of technology as a link between a more prosperous economic future and a cleaner envi- ronment, and discussed the benefits of carbon sequestration. The efficiency of power plants was discussed as well as the potential for public/private power partner- ships. A spokesman for General Electric indicated that European IGCCs, fueled by coal as well as other fuels, are performing well, and he predicted a growth in IGCC over the next few years. Coal provides over 50 percent of electricity production in Germany, and 97 percent in Poland. For China and India, the figure is 70 percent. Privatization was seen by conference participants to be of key importance. The World Energy Council sees market-oriented restructuring as a main condition to clean coal technology deployment. Such a restruc- turing may be able to surmount the barriers of poor coal quality. Prior to the conference, the FE delegation and private sector representatives met with representatives of the Turkish energy sector who asked for U.S. techni- cal advice in the privatization process. As a result of the meeting, FE will draft an Energy Science and Technology Agreement to formalize the effort. At the meeting, Turkish officials also expressed interest in U.S. mining technology and the possibility of informa- tion exchanges. 4-24 Program Update 1999 A The Director of FE’s Office of Import and Export (middle) and the FE Assistant Secretary (right) address WEC conference attendees. Trade Mission Activities in FY1999 China. In April 1999, the U.S.-China Energy and Environmental Technology Center (EETC) held its first annual Board of Directors meeting. At the meet- ing, held in Washington, D.C., the Board of Directors reviewed accomplishments over the past year, as well as new directions. EETC is funded jointly by DOE, U.S. Environmental Protection Agency and the Chinese State Science and Technology Commission. The U.S./ China Institute has a cooperative agreement with U.S. DOE to manage and operate the EETC. Tulane and Tsinghua Universities, in turn, are subcontracted to run the day-to-day operations. EETC’s mission is to enhance the competitiveness and adoption of U.S. clean and environmentally superior technologies in China by focusing on education and training, promot- ing the use and profitability of U.S. technology, and supporting policy development in China to encourage the responsible use of coal. Over the past year, the Hydrocarbon Technologies, Inc. (HTI) direct liquefaction project, proposed to be located near Shaanxi Province, has advanced from pre- feasibility to the feasibility study phase. EETC has acted to promote the project to the Chinese Government. Other liquefaction projects, sponsored by German and Japanese companies with financial support from their respective governments, are also contending for the ultimate award. A commercial plant using HT] technol- ogy could produce 50,000 barrels/day of gasoline and diesel fuel using 10,000-12,000 tons/day of bituminous coal. The pre-feasibility study established that the project can use a variety of Chinese coals. The feasibili- ty study will include further testing as well as evaluation of economics and project financing. DOE has supported test runs on Chinese coals at a bench test unit. The Chinese government appears ready to make a decision on another project, a 300-MW commercial IGCC project to be located in Yantai in the Shandong Province. Foreign investment is being sought. Con- struction is expected to start in 2000-2001. Since 1993, DOE and U.S. industry have been working closely with the Chinese government, industry, and R&D organizations to help China develop this first IGCC project. EETC is also supporting the efforts of The Bab- cock & Wilcox Company (B&W) to secure an FGD joint venture from China’s State Power Corporation, a government agency that has decided to increase the engineering and fabrication capacity of FGD systems throughout China. B&W was a co-sponsor with the EETC of the February 1998 U.S.-China Workshop on SO, Control Technology. In other areas, EETC has been sponsoring studies of upgrading coal-based fertilizer plants to become more energy efficient. EETC has helped the city of Chongqing convert its fertilizer plant to natural gas, but in most cases natural gas sources are not available. Finally, EETC will broaden its activities in climate change and CO, reduction, establishing a special task force and continuing work in coal gasification, coal washing, biomass gasification for distributed power, and ash utilization. India. The Office of Fossil Energy, with funding from the USAID, and in conjunction with Tennessee Valley Authority (TVA) and EPRI, is preparing to support the efficiency improvement testing aimed at greenhouse gas reduction at the 210-MW Unit No. 7 of the Maharasthtra State Electricity Board’s coal-fired Koradi Power Plant in India. In another effort, FE, along with USAID support, sent an electrostatic precipitator (ESP) specialist to India to determine the effectiveness of “sodium condi- tioning” on ESP performance, given the high ash loading conditions experienced at Indian coal-fired power plants. With a very simple test setup, approxi- mately 0.25 percent by weight of sodium was added to the coal being fed to one of the four 67-MW units at a power plant in Korba, India. The results were out- standing. The normal stack particulate loading of 340 milligrams per standard cubic meter (a very dirty looking stack plume) was reduced to 60 milligrams per standard cubic meter, which is an essentially clean stack to the naked eye. The sodium material used is considered a waste product and the primary cost was shipping; thus the addition to the cost of electricity was less than one-half of one cent per kilowatt-hour. Poland. Air quality in many Central European cities has degraded during the past several decades A The Bilaspur Coal Washery Project in the state of Madhya Pradesh is India’s first private commercial coal washery for electric power generation. with heavy use of solid fuels for heating. Since 1990, the U.S. Department of Energy has been involved ina program aimed at reducing air pollution caused by small coal-fired sources in Krakow, Poland. Although the activity is focused on the city of Krakow, it is expected that the results will be applicable to the entire region. Formal basis for the U.S. assistance to Poland in this area was provided by the Support for Eastern European Democracy Act of 1989 (SEED). Part of this legislation directed that DOE cooperate with U.S. and Polish experts to undertake an assessment and imple- mentation program in Poland to use fossil fuels cleanly in small-scale combustion equipment. Funding for this program has been provided to DOE by the USAID. The SEED program was specifically directed toward the problems of low altitude emissions sources in Krakow. A city of 750,000 and Poland’s capital from the 11" to 17" centuries, Krakow is a major university and industrial center, and contains numerous historic buildings. The city has been included in the United Nations Educational, Scientific and Cultural Organization (UNESCO) list of world cultural heritag- es. The program was designed to assess the total problem of low-level emission sources within the center of “Old Krakow” and progress to the outskirts; identify specific large emission sources; determine cost-effective approaches for long-term remediation; and use a multi-faceted technical approach to imple- ment new technologies. Air quality has improved dramatically since the program began. A number of major emitters have already had numerous thermal/ burner/particulate control systems installed. The program is currently in its last phase, in which many particulate sources are being closed due to connection to an expanded district heating system, home stoves are having electric heating elements installed, and electrical upgrading is being implemented. United States funding provides new equipment, preferably through joint US-Polish suppliers, to a variety of city, regional, and private energy offices and partners. A significant upgrade to the large Polish American Children’s Hospital is also underway—the only dedi- cated pediatric medical research facility in Poland. A number of projects have evolved from the Krakow effort and have been implemented in other parts of Poland and Central Europe. Due to lower initial capital costs and operating costs, mechanical particulate collectors traditionally have been installed in industrial applications in Poland rather than more complex devices. One such device is the core separa- tor developed by LSR Technologies, of Acton, Massa- chusetts. Original development work on the core separator was done under the DOE Small Business Innovative Research Program. Dust emissions from this device are typically 3—6 times lower than from the best cyclone collectors, and its performance approach- es that of fabric filters and electrostatic precipitators, but at a much lower cost. Within Krakow, core separa- tors were installed at a 6-MW stoker fired boiler in a motor manufacturing plant and at a 1.5-MW boiler located at the central bus service center. Particulate Program Update 1999 4-25 removal at these sites averaged 94 percent. Another 52 core separators are either in operation or being in- stalled within Poland and neighboring countries. The total Krakow program continues to show marked improvement in air quality due to the many emission sources that are either being controlled or eliminated. Core separators alone are removing more than 575,000 metric tons per year of particulates in the region. Through 1998, it is estimated that more than 126,000 metric tons of CO, emissions per year have been eliminated; with new ongoing remediation projects, another 25,000 metric tons/year will be eliminated. Upgrading the large Children’s Hospital complex alone will eliminate approximately 15,000 tons/year of CO,, as well as closure of a large coal- fired dedicated (17.5 MW) boiler. Clearly, the joint U.S./Poland effort is having a positive environmental impact in the region. Russia. During June 1999, a delegation from DOE’s Office of Fossil Energy and Office of Interna- tional Affairs visited Moscow, Russia for technology information exchange with Russian organizations concerned with coal, coal technology, and power production. Specific discussions were directed toward the use of clean and efficient coal technologies as a component of environmental protection, including (1) new technologies and equipment to improve combus- tion efficiency in thermal power plants and advanced gas turbines and gasification combined-cycle technolo- gies; and (2) a common understanding of the present and future strategic value of fossil fuels for electric power and fuels production in Russia and in the U.S. Russian organizations visited included: the Fossil Fuels Institute of the Ministry for Fuel and Energy of Russia; the All-Russian Thermal Engineering Institute; the Office of the Deputy Minister, Ministry of Fuel and 4-26 Program Update 1999 Energy of Russia; the Moscow Center for Energy Efficiency; and the Committee of Coal Industry of the Russian Federation. As a result of the visit, a number of areas for cooperation were identified that could be of potential mutual benefit. It was agreed that DOE would initiate preparation of a draft Annex under the existing bilateral Science and Technology Agreement, specific to the development and utilization of clean and efficient fossil fuels. The Annex will identify and institutionalize cooperation between the DOE and Russian counterpart governmental organizations. Taiwan. Agreements are being prepared with Taiwan allowing FE to provide technical expertise, training, and scientific exchange activities in the areas of clean coal technology, coal utilization, and waste and by-product utilization. A major expected outcome includes FE technical support for an IGCC feasibility study. FE would advise Taiwan on project financing (a mix of Taiwan government and private funding), plant siting, and technology selection. The agreement would first be signed between FE and the Taipei Economic and Cultural Representative Office (TECRO), and then between the Energy Commission of the Ministry of Economic Affairs and the American Institute in Tai- wan. After the agreements are finalized, both Taiwan and the United States hope to branch out into other cooperative work—fuel cell development, independent power production, rural electrification, computer modeling for energy policy decisions, environmental management, cement and steel factory cleanup, and paper mill waste treatment. Tulane University’s U.S./ China Institute has been active in coordinating and supporting FE efforts on these agreements. FE began working a year and-a-half ago with Taiwan to promote adoption of clean coal technologies. Taiwan imports about 96 percent of its primary energy—mostly oil, coal, and liquefied natural gas. The country seeks to develop a long-term energy policy and emissions control strategy, preferably regional in scope. Ukraine. U.S. and Ukrainian participants met in April 1999 in Research Triangle Park, North Carolina to discuss progress to date on an EPA and DOE spon- sored fuel reburning project in Ladyzhin, Ukraine. A multi-fuel reburn system (capable of using natural gas, coal, heavy fuel oil, or combinations thereof) is being installed to reduce NO, emissions from Unit 6, a 300- MW wet-bottom coal-fired boiler at Ladyzhin Power Station, 200 miles south of Kiev. Under an interagency agreement, funding is provided by EPA’s Environmen- tal Technology Initiative. Technical guidance for process design and operation are provided jointly by EPA’s National Risk Management Research Laboratory and FE. The project follows an earlier collaborative effort in 1992 (in which DOE did not participate) where a natural gas reburning system was installed at Ladyzhin Power Station Unit 4. This operation reduced NO, emissions by more than 50 percent. The success of this early demonstration encouraged the Ladyzhin Power Station and the Ukrainian Power Ministry to extend the application of this technology to other units. These units were needed to help meet pending regulations that will place a tax on all emissions. Fuel cost, availabili- ty, and distribution problems in Ladyzhin made a multi-fuel approach desirable. In the reburn method, 5—20 percent of total boiler fuel is injected downstream of the main burners to create a fuel-rich zone, followed by injection of burn- out air, and can remove 50 percent or more of uncon- trolled NO, emissions. The technology is very promis- ing for Ukraine and Russia, where 50 percent of all boilers are of a slagging or wet-bottom design, for which conventional low-NO, burners are not generally applicable. Energy and Environmental Research Corporation of Irvine, California is supporting system design. Component design, fabrication, and installation are being done by Ladyzhin Power Station staff. To date, the plant has installed separate coal mills for supplying the reburn fuel and has conducted preliminary tests of the coal reburn system. Nitrogen oxides reductions of 25-35 percent have been achieved compared to opera- tion without injection of reburning fuel, i.e., using only the overfire air ports component of the reburning system. During operation with coal as the reburning fuel, this performance translates into total NO, reduc- tions of 50 percent. Additional system optimization is currently underway to improve the reburn coal feed rate and NO, reduction capacity. Program Update 1999 4-27 5. CCT Projects Introduction CCT Program demonstrations provide a portfolio of technologies that will enable coal to continue to provide low-cost, secure energy vital to the nation’s economy while satisfying energy and environmental goals well into the 21“ century. This is being carried out by addressing four basic market sectors: (1) environmental control devices for existing and new power plants, (2) advanced electric power generation for repowering existing facilities and providing new generating capacity, (3) coal processing for clean fuels to convert the nation’s vast coal resources to clean fuels, and (4) industrial applications dependent upon coal use. In response to the initial thrust of the CCT Program, operations have been completed for 18 of 19 projects that address SO, and NO, control for coal- fired boilers. The resultant technologies provide a suite of cost-effective control options for the full range of boiler types. The 19 environmental control device projects are valued at more than $702 million. These include seven NO, emission control systems installed in more than 1,750 MWe of utility generating capacity, five SO, emissions systems installed on approximately 770 MWe, and seven combined SO,/NO, emission control systems installed or planned on more than 665 MWe of capacity. To respond to load growth as well as growing environmental concerns, the program provides a range of advanced electric power generation options for both repowering and new power generation. These ad- vanced options offer greater than 20 percent reductions in greenhouse gas emissions; SO,, NO,, and particulate emissions far below New Source Performance Stan- dards (NSPS); and salable solid and liquid by-products in lieu of solid wastes. Over 1,800 MWe of capacity are represented by 11 projects valued at more than $2.8 billion. These projects include five fluidized-bed combustion (FBC) systems, four integrated gasification combined-cycle (IGCC) systems, and two advanced combustion/heat engine systems. These projects will provide the demonstrated technology base necessary to meet new capacity requirements in the 21“ century. Also addressed are approaches to converting raw, run-of-mine coals to high-energy-density, low-sulfur products. These products have application domestical- ly for compliance with the Clean Air Act Amendments of 1990 (CAAA). Internationally, both the products and processes have excellent market potential. Valued at more than $519 million, the five projects in the coal processing for clean fuels category represent a diversi- fied portfolio of technologies. Three projects involve the production of high-energy-density solid fuels, one of which also produces a liquid product equivalent to No. 6 fuel oil. A fourth project is demonstrating a new methanol production process. A fifth effort comple- ments the process demonstrations by providing an expert computer software system that enables a utility to assess the environmental, operational, and cost impact of utilizing coals not previously burned at a facility, including upgraded coals and coal blends. Projects also were undertaken to address pollution problems associated with coal use in the industrial sector. These included dependence of the steel industry on coke and the inherent pollutant emissions in coke making; reliance of the cement industry on low-cost indigenous, and often high-sulfur, coal fuels; and the need for many industrial boiler operators to consider switching to coal fuels to reduce operating costs. The five industrial applications projects have a combined value of nearly $1.3 billion. Projects encompass substitution of coal for 40 percent of coke in iron making, integration of a direct iron making process with the production of electricity, reduction of cement kiln emissions and solid waste generation, and demonstrations of an industrial-scale slagging combus- tor and a pulse combustor system. The remainder of this section contains a discussion of the technologies being demonstrated and fact sheets for each project. A The CCT projects are spread across the nation in 18 states, indicated in white. Project Fact Sheets 5-1 Technology Overview Environmental Control Devices Environmental control devices are those technolo- gies retrofitted to existing facilities or installed on new facilities for the purpose of controlling SO, and NO, emissions. Although boilers may be modified and combustion affected, the basic boiler configuration and function remains unchanged with these technologies. SO, Control Technology. Sulfur dioxide is an acid gas formed during coal combustion, which oxidizes the inorganic, pyritic sulfur (Fe,S), and organically-bound sulfur in the coal. Identified as a precursor to formation of acid rain, SO, was targeted in Title IV of the CAAA. Phase I of Title IV, effective in 1995, affected 261 coal-fired units nationwide. The required SO, reduction was moderate and largely met by switching to low-sulfur fuels. In year 2000, Phase II of Title IV comes into effect, impacting all fossil-fuel- fired units, but most of all, the approximately 700 pre- NSPS coal-fired facilities. Under the stricter Phase II requirements, compliance by fuel switching alone is unlikely. The CAAA provides utilities flexibility in control strategies through SO, allowance trading. This permits a range of control options to be applied by a utility, as well as allowance purchasing. Recognizing this, the CCT Program has sought to provide a portfo- lio of SO, control technologies. Sulfur dioxide control devices embody those technologies that condition and act upon the flue gas resulting from combustion, not the combustion itself, for the purpose of removing only SO,. Three basic approaches evolved, driven primarily by different conditions that exist within the pre-NSPS boiler 5-2 Project Fact Sheets population impacted by the CAAA. There is a tremen- dous range in critical factors, e.g., size, type, age, and space availability. On one end of the spectrum are the smaller, older boilers with limited space for adding equipment. For these, sorbent injection techniques hold promise. Sorbent is injected into the boiler or the ductwork, and humidification is incorporated in some fashion to properly condition the flue gas for efficient SO, capture. Equipment size and complexity are held to a minimum to keep capital costs and space requirements low. Both limestone and lime sorbents are used. Limestone costs are about one-third that of hydrated lime; but limestone must be conditioned (calcined), and even then, it is less effective in SO, capture (under simple sorbent injection conditions) than hydrated lime. Where limestone is used, it is injected in the boiler to produce calcium oxide, which reacts with SO, to form solid compounds of calcium sulfite and calcium sulfate. Both limestone and lime injection require the presence of water (humidification) and a calcium-to-sulfur (Ca/S) molar ratio of about 2.0 for sulfur capture efficiencies of 50 to 70 percent. In the mid-range of the spectrum are 100- to 300- MWe boilers less than 30 years old and somewhat space constrained. For many of these, an increase in higher equipment cost is justified by enhanced performance. The approach involves introduction of a reactor vessel in the flue gas stream to create conditions to enhance SO, capture beyond that achievable with the simpler sorbent injection systems. Lime, as opposed to limestone, is used and sulfur capture efficiencies up to 90 percent can be achieved at Ca/S molar ratios of 1.3 to 2.0. This category of control device is called a spray dryer (because the solid by-product from the reaction is dry). A Unique CT-121 SO, scrubber at Plant Yates combined a number of functions and eliminated process steps. At the other end of the spectrum are the larger (300-MWe and more) boilers with some latitude in space availability, as well as new capacity additions. For these boilers, advanced flue gas desulfurization (AFGD) wet scrubbers, with higher capital cost but higher sulfur capture efficiency than other approaches, become cost effective. These systems apply larger and somewhat more complex reactors that drive up the capital cost. However, the sorbent is limestone, and SO, removal efficiencies greater than 90 percent are achieved at a Ca/S molar ratio of about 1.0, making operating costs significantly lower than those of the other two approaches. Furthermore, although the initial AFGD solid by-product is in slurry form, it is dewa- tered to produce gypsum—a salable product. Under the CCT Program, two sorbent injection systems, one spray dryer, and two AFGD processes, were successfully demonstrated. All have completed testing. Exhibit 5-1 briefly summarizes the characteris- tics and performance of the technologies that are described in more detail in the project fact sheets. NO, Control Technology. Nitrogen oxides (NO_) are formed from oxidation of nitrogen contained within Exhibit 5-1 CCT Program SO, Control Technology Characteristics Coal Sulfur so, Fact Project Process Content Reduction Sheet Confined Zone Dispersion Flue Gas Sorbent injection—in-duct lime sorbent injection and humidification 1.5-2.5% 50% 5-24 Desulfurization Demonstration LIFAC Sorbent Injection Desulfurization Sorbent injection—furnace sorbent injection (limestone) with vertical 2.0-2.9% 70% 5-28 Demonstration Project humidification vessel and sorbent recycle 10-MWe Demonstration of Gas Suspension Spray dryer—vertical, single-nozzle reactor with integrated sorbent 2.7-3.5% 60-90% 5-20 Absorption particulate recycle (lime sorbent) Advanced Flue Gas Desulfurization AFGD—cocurrent flow, integrated quench absorber tower, and reaction 2.254.7% 94% 5-32 Demonstration Project tank with combined agitation/oxidation (gypsum by-product) Demonstration of Innovative Applications AFGD—forced flue gas injection into reaction tank (Jet Bubbling 1.2-3% 90+% 5-36 of Technology for the CT-121 FGD Process Reactor") for combined SO, and particulate capture (gypsum by-product) V Pictured here, the 10-MWe AirPol gas suspension absorption demonstration unit. Y Shown is the water inlet connections to the Pure Air absorber module. | Lc a LAL a Project Fact Sheets 5-3 the coal (i.e., “fuel-bound NO.”) and oxidation of the nitrogen in the air at high temperatures of combustion (ie., “thermal NO.”). To control fuel-bound NO. formation, it is important to limit oxygen at the early stages of combustion. To control thermal NO,, it is important to limit peak temperatures. Nitrogen oxides were identified both as a precur- sor to acid rain (targeted under Title IV of the CAAA) and as a contributor to ozone formation (targeted under Title I). Phase I of Title IV, effective in 1995, required 265 wall- and tangentially-fired coal units to reduce emissions to 0.50 and 0.45 Ib/10° Btu, respectively. In 2000, Phase II of Title IV will come into effect, impacting all fossil-fueled units, but most of all, the balance of the pre-NSPS coal-fired units (see Exhibit 5-2). Ozone nonattainment prompted the EPA to issue a NO. transport State Implementation Plan (SIP) call for 22 states and the District of Columbia to cut NO, emissions 85 percent below 1990 rates or achieve a 0.15 Ib/10° Btu emission rate by May 2003. The CCT Program has sought to provide a number of NO, control options to cover the range of boiler types and emission reduction requirements. Control of NO, emissions can be accomplished by either modifying the combustion process or acting upon the products of combustion (or combinations thereof). Combustion modification technologies include low-NO, burners (LNBs), advanced overfire air (AOFA), and reburning processes using either natural gas or coal. Post-combustion processes used to act upon flue gas include selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR). LNBs regulate the initial fuel-air Exhibit 5-2 Group | and 2 Boiler Statistics and Phase II NO, Emission Limits mixture, velocities, and turbulence to create a fuel-rich flame core and control the rate at which additional air required to complete combustion is Number Phase II of NO, Emission Limits mixed. This staging of combustion avoids a highly oxidized environment and hot spots conducive to fuel-bound Boiler Types Boilers (Ib/10° Btu) Group 1 Tangentially-fired 299 0.40 Dry-bottom, wall-fired 308 0.46 Group 2 Cell burner 36 0.68 Cyclone >155 MWe 55 0.86 Wet-bottom, wall-fired >65 MWe 26 0.84 Vertically fired 28 0.80 Source: Environmental Protection Agency, Nitrogen Oxides Emission Reduction Program, Final Rule for Phase II, Group | and Group 2 Boilers (http://www.epa.gov/docs/acidrain/noxfs3.html). NO, and thermal NO, formation. LNBs alone typically can achieve 40 to 50 percent NO, reduction. AOFA involves injection of air above the primary combustion zone to allow the primary combustion to occur without the amount of oxygen needed for complete combustion. This oxygen deficiency mitigates fuel-bound NO, formation. AOFA injected at high velocity creates turbulent mixing to complete the combustion in a gradual 5-4 Project Fact Sheets A Shown are The Babcock & Wilcox Company DRB- XCL* burners installed on a down-fired boiler. fashion at lower temperatures to mitigate thermal NO. formation. Usually, AOFA is used in combination with LNBs; but alone, AOFA can achieve 10 to 25 percent NO, emission reductions. The LNB/AOFA systems generally can achieve NO, emission reductions of 37 to 68 percent, depending upon boiler type. Advanced control systems using artificial intelli- gence are also becoming an integral part of NO, control systems. These systems can handle the numerous parameters and optimize performance to reduce NO, while enhancing boiler performance. In reburning, a percentage of the fuel input to the boiler is diverted to injection ports above the primary combustion zone. Either gas or coal is typically used as the reburning fuel to provide 10 to 30 percent of the heat input to the boiler. The reburning fuel is injected to create a fuel-rich zone deficient in oxygen (a reducing rather than oxidizing zone). NO, entering this zone is stripped of oxygen, resulting in elemental nitrogen. Combustion is completed in a burnout zone where air is injected by an AOFA system. Reburning has application to all boiler types, including cyclone boilers, and can achieve NO, emission reductions of 50 to 67 percent. SCR and SNCR can be used alone or in combina- tion with combustion modification. These processes use ammonia or urea in a reducing reaction with NO. to form elemental nitrogen and water. SNCR can only be used at high temperatures (1,600 to 2,200 °F) where a catalyst is not needed. SCR is typically applied at temperatures between 600 to 800 °F. Generally, SNCR and SCR systems alone can achieve NO, emission reductions of 30 to 50 percent and 80 to 90+ percent, respectively. Under the CCT Program, seven NO, control technologies were assessed encompassing LNBs, AOFA, reburning, SNCR, SCR, and combinations thereof. Six of the seven of the projects have complet- ed operations. One project has been extended. Exhibit 5-3 briefly summarizes the characteristics and performance of the technologies that are described in more detail in the project fact sheets. Combined SO,/NO, Control Technology. Combined SO,/NO, control systems encompass those technologies that combine previously described control methods and those that apply other synergistic tech- niques. Three of the projects combine either LNBs or gas reburning with sorbent injection. In one of these, SNCR is used with LNBs to enhance performance. Another project combines a number of techniques to improve overall system performance, such as LNBs with SNCR, unique space-saving and durable wet- scrubber design, sorbent additive, and artificial intelligence controls. The balance of the seven projects use synergistic methods not previously described. SO,-NO,-Rox Box™ incorporates an SCR catalyst in a high-temperature filter bag for NO, control and applies sorbent injection for SO, control. The high- temperature filter bag, operated in a standard pulsed-jet baghouse, protects the SCR catalyst, allows operation at optimal NO, control temperatures, forms a sorbent cake on the surface to enhance SO, capture, and provides high-efficiency particulate capture. Exhibit 5-3 CCT Program NO, Control Technology Characteristics Boiler Size/ NO, Fact Project Process Type Reduction Sheet Demonstration of Coal Reburning for Cyclone Coal reburning—30% heat input 100-MWe/cyclone 52-62% 5-46 Boiler NO, Control Evaluation of Gas Reburning and Low-NO, Burners LNB/gas reburning/AOFA—13-—18% gas heat input 172-MWe/wall 37-65% 5-54 on a Wall-Fired Boiler Micronized Coal Reburning Demonstration Coal reburning—14% heat input (tangentially-fired) and 148-MWe/tangential 28% 5-58 for NO, Control 17% heat input (cyclone) 50-MWe/cyclone 59% Full-Scale Demonstration of Low-NO, Cell Burner LNB—separation of coal and air ports on plug-in unit 605-MWe/cell burner 48-58% 5-50 Retrofit Demonstration of Advanced Combustion Techniques LNB/AOFA—advanced LNB with separated AOFA 500-M We/wall 68% 5-42 for a Wall-Fired Boiler and artificial intelligence controls 180 MWe Demonstration of Advanced Tangentially- LNB/AOFA—advanced LNB with close-coupled 180-MWe/tangential 37-45% 5-66 Fired Combustion Techniques for the Reduction of NO, and separated overfire air Emissions from Coal-Fired Boilers Demonstration of Selective Catalytic Reduction SCR—eight catalysts with different shapes and 8.7-MWe/various 80% 5-62 Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers chemical compositions Project Fact Sheets 5-5 SNOX™ uses SCR followed by catalytic oxida- tion of SO, to SO, with condensation of the SO, in the presence of water to produce sulfuric acid. Following the SCR with the catalytic oxidation allows the SCR to operate at optimal ammonia concentration without worry of ammonia slip (ammonia passing to the second catalyst is broken down into water vapor, nitrogen, and a small amount of NO,). Furthermore, most particulates passing through the upstream baghouse are captured in the sulfuric acid condensing unit. The system produces no solid waste. NOXSO uses a single, regenerable adsorber (spherical alumina beads impregnated with sodium carbonate) to capture both SO, and NO,. The adsorber is used in a fluidized bed to achieve effective mixing with the flue gas. The adsorber is then processed through a regenerator system to release the NO, and SO, before return to the fluidized bed. The flue gas passes through a baghouse to remove particulates. Six of the seven combined SO,/NO, control technology projects have completed operations and one is on hold. Exhibit 5-4 briefly summarizes the charac- teristics and performance of the technologies that are described in more detail in the project fact sheets. A The SNOX™ SCR catalyst and the catalytic oxidation system has been retained as a permanent part of the Niles Station. Exhibit 5-4 CCT Program Combined SO,/NO, Control Technology Characteristics Coal Sulfur SO,/NO, Fact Project Process Content Reduction Sheet LIMB Demonstration Project Extension and LNB/sorbent injection—furnace and duct injection, calcium-based 1.6-3.8% 60-70%/40-50% 5-86 Coolside Demonstration sorbents Integrated Dry NO./SO, Emissions LNB/SNCR/sorbent injection—calcium- and sodium-based 0.4% 70%/62-80% 5-94 Control System sorbents used in duct injection Enhancing the Use of Coals by Gas Reburning Gas reburning/sorbent injection—calcium-based sorbents used in 3.0% 50-60% /67% 5-82 and Sorbent Injection duct injection Milliken Clean Coal Technology Demonstration LNB/SNCR/wet scrubber—sorbent additive and space-saving, 1.5-4.0% 98%/53-58% 5-90 Project durable scrubber design SO.-NO,-Rox Box™ Flue Gas Cleanup SCR/high temperature baghouse/sorbent injection—SCR in high- 3.4% 80-90% /90% 5-78 Demonstration Project temperature filter bag and calcium-based sorbent injection SNOX™ Flue Gas Cleaning Demonstration SCR/oxidation catalyst/sulfuric acid condenser—synergistic 3.4% 95%/94% 5-74 Project catalyst effect and no solid waste Commercial Demonstration of the NOXSO Regenerable adsorbent—spherical alumina beads impregnated 3.4% (planned) 98% (goal)/75% (goal) 5-72 SO,/NO, Removal Flue Gas Cleanup System with sodium carbonate in fluidized-bed adsorber 5-6 Project Fact Sheets Advanced Electric Power Generation Technology Advanced electric power generation technologies enable the efficient and environmentally superior generation of electricity. The advanced electric power generation projects selected under the CCT Program are responsive to capacity expansion needs requisite to meeting long-term demand, off setting nuclear retire- ments, and meeting stringent CAAA emission limits effective in 2000. These technologies are character- ized by high thermal efficiency, very low pollutant emissions, reduced CO, emissions, few solid waste problems, and enhanced economics. Advanced electric power generation technologies may be deployed in modules, allowing phased construction to better match demand growth, and to meet the smaller capacity requirements of municipal, rural, and nonutility generators. There are five generic advanced electric power generation technologies demonstrated in the CCT Program. The characteristics of these five technologies are outlined here, and the specific projects and technologies are presented in more detail in the fact sheets. Fluidized-Bed Combustion. Fluidized-bed combustion (FBC) reduces emissions of SO, and NO, by controlling combustion parameters and by injecting a sorbent (such as crushed limestone) into the combus- tion chamber along with the coal. Pulverized coal mixed with the limestone is fluidized on jets of air in the combustion chamber. Sulfur released from the coal as SO, is captured by the sorbent in the bed to form a solid calcium compound that is removed with the ash. The resultant waste is a dry, benign solid that can be disposed of easily or used in agricultural and construc- tion applications. More than 90 percent of the SO, can be captured this way. At combustion temperatures of 1,400 to 1,600 °F, the fluidized mixing of the fuel and sorbent enhances both combustion and sulfur capture. The operating temperature range is about half that of a conventional pulverized-coal boiler and below the temperature at which thermal NO, is formed. In fact, fluidized-bed NO, emissions are about 70 to 80 percent lower than those for conventional pulverized-coal boilers. Thus, fluidized-bed combustors substantially reduce both SO, and NO, emissions. Also, fluidized-bed combustion has the capability of using high-ash coal, whereas conventional pulverized-coal units must limit ash content in the coal to relatively low levels. A The 110-MWe Nucla ACFB demonstration enabled Pyropower Corporation (now owned by Foster Wheeler) to save almost 3 years in establishing a commercial line of ACEB units. Two parallel paths were pursued in fluidized-bed development—bubbling and circulating beds. Bub- bling beds use a dense fluid bed and low fluidization velocity to effect good heat transfer and mitigate erosion of an in-bed heat exchanger. Circulating fluidized-beds use a relatively high fluidization velocity that entrains the bed material, in conjunction with hot cyclones to separate and recirculate the bed material from the flue gas before it passes to a heat exchanger. Hybrid systems have also evolved from these two basic approaches. Fluidized-bed combustion can be either atmo- spheric (AFBC) or pressurized (PFBC). AFBC operates at atmospheric pressure while PFBC operates at pressure 6 to 16 times higher. PFBC offers higher efficiency by using both a gas turbine and steam turbine. Consequently, operating costs and waste are reduced relative to AFBC, as well as boiler size per unit of power output. Second-generation PFBC integrates the combustor with a pyrolyzer (coal gasifier) to fuel a gas turbine (topping cycle), the waste heat from which is used to generate steam for a steam turbine (bottoming cycle). The inherent efficiency of the gas turbine and waste heat recovery in this combined-cycle mode significant- ly increases overall efficiency. Such advanced PFBC systems have the potential for efficiencies over 50 percent. Of the five fluidized-bed combustion projects, two have successfully completed demonstration (one PFBC and one AFBC), and the other three are in the project definition and design phase. Integrated Gasification Combined-Cycle. The integrated coal gasification combined-cycle process has four basic steps: (1) fuel gas is generated from coal reacting with high-temperature steam and an oxidant Project Fact Sheets 5-7 (oxygen or air) in a reducing atmosphere; (2) the fuel gas is either passed directly to a hot-gas cleanup system to remove particulates, sulfur, and nitrogen compounds or first cooled to produce steam and then cleaned conventionally; (3) the clean fuel gas is combusted in a gas turbine generator to produce electricity; and (4) the residual heat in the hot exhaust gas from the gas turbine is recovered in a heat recovery steam generator, and the steam is used to produce additional electricity in a steam turbine generator. Integrated gasification combined-cycle systems are among the cleanest and most efficient of the emerging clean coal technologies. Sulfur, nitrogen compounds, and particulates are removed before the fuel is burned in the gas turbine, that is, before combustion air is added. For this reason, there is a much lower volume of gas to be treated than in a postcombustion scrubber. The chemical composition of the gas requires that the gas stream must be cleaned to a high degree, not only to achieve low emissions, but to protect downstream components, such as the gas turbine, from erosion and corrosion. Ina coal gasifier, the sulfur in the coal is released in the form of hydrogen sulfide (H,S) rather than as SO,. In some IGCC systems, much of the sulfur- containing gas is captured by a sorbent injected into the gasifier. Others use existing proven commercial hydrogen sulfide removal processes, which remove more than 99 percent of the sulfur, but require the fuel to be cooled, which is an efficiency penalty. There- fore, hot-gas cleanup systems are now being demon- strated. In these cleanup systems, the hot coal gas is passed through a bed of metal oxide particles, such as zinc oxides. Zinc oxide can absorb sulfur contami- nants at temperatures in excess of 1,000 °F, and the compound can be regenerated and reused with little 5-8 Project Fact Sheets loss of effectiveness. Produced during the regeneration stage are salable sulfur, sulfuric acid, or sulfur- containing compounds that may be used to produce useful by-products. The technique is capable of removing more than 99.9 percent of the sulfur in the gas stream. With hot-gas cleanup, IGCC systems have the potential for efficiencies of over 50 percent. High levels of nitrogen removal are also possible. Some of the coal’s nitrogen is converted to ammonia, which can be almost totally removed by commercially available chemical processes. NO, formed in the gas turbine can be held to well within allowable levels by staged combustion in the gas turbine or by adding moisture to control flame temperature. Integrated Gasification Fuel Cell. A typical fuel cell system using coal as fuel includes a coal gasifier with a gas cleanup system, a fuel cell to use the coal gas to generate electricity (direct current) and heat, an inverter to convert direct current to alternating current, and a heat-recovery system. The heat-recovery system would be used to produce additional electric power in a bottoming steam cycle. A Shown is the Coltec coal-fired diesel being installed at the University of Alaska. Energy conversion in fuel cells is more efficient than traditional energy conversion devices (up to 60 percent, depending on fuel and type of fuel cell). Fuel cells directly transform the chemical energy of a fuel and an oxidant (air or oxygen) into electrical energy instead of going through an intermediate step, i.e., burner, boiler, turbines, and generators. Each fuel cell includes an anode and a cathode separated by an electrolyte layer. In a coal gasification/fuel cell application, coal gas is supplied to the anode and air is supplied to the cathode to produce electricity and heat. Of the four IGCC projects, three are in operation and one is in the project definition and design phase. Coal-Fired Diesel. Coal-fired diesels use either a coal-oil or coal-water slurry fuel to drive an electric generation system. The hot exhaust from the diesel engine is routed through a heat-recovery unit to pro- duce steam for a steam-turbine electric generating system (combined cycle). Environmental control systems for SO,, NO,, and particulate removal treat the cooled exhaust before release to the atmosphere. The diesel system is expected to achieve 41 to 48 percent thermal efficiencies. The 5- to 20-MWe capacity range of the technology is most amenable to distributed power applications. The CCT coal-fired diesel project is in construction. Slagging Combustor. Many new coal burning technologies are designed to remove the coal ash as molten slag in the combustor rather than the furnace. Most of these slagging combustors are based on a cyclone concept. In a cyclone combustor, coal is burned in a separate chamber outside the furnace cavity. The hot combustion gases then pass into the boiler where the actual heat exchange takes place. An advantage of a cyclone combustor is that the ash is kept out of the furnace cavity where it could collect on boiler tubes and lower heat transfer efficien- cy. To keep ash from being blown into the furnace, the combustion temperature is kept so hot that mineral impurities melt and form slag, hence the name slagging combustor. A vortex of air (the cyclone) forces the slag to the outer walls of the combustor where it can be removed as waste. Results to date show that by positioning air injec- tion ports so that coal is combusted in stages, NO, emissions can be reduced by 70 to 80 percent. Inject- ing limestone into the combustion chamber has the potential to reduce sulfur emissions by 90 percent in combination with a spray dryer absorber. Advanced slagging combustors could replace oil-fired units in both utility and industrial applications or be used to retrofit older, conventional cyclone boilers. The CCT advanced slagging combustor project is in operation. Exhibit 5-5 summarizes the process characteristics and size of the advanced electric power generating technologies presented in more detail in the project fact sheets. Exhibit 5-5 CCT Program Advanced Electric Power Generation Technology Characteristics Combustion Demonstration Project Project Process Size Fact Sheet Fluidized-Bed Combustion McIntosh Unit 4A PCFB Demonstration Project Pressurized circulating fluidized-bed combustion 137-MWe (net) 5-100 McIntosh Unit 4B Topped PCFB McIntosh 4A with pyrolyzer and topping combustor 240-MWe (net) 5-102 Demonstration Project Tidd PFBC Demonstration Project Pressurized bubbling fluidized-bed combustion 70-MWe 5-106 JEA Large-Scale CFB Atmospheric circulating fluidized-bed combustion 297.5-MWe (gross) 5-104 265-MWe (net) Repowering Project cold gas cleanup Nucla CFB Demonstration Project Atmospheric circulating fluidized-bed combustion 100-MWe 5-110 Integrated Gasification Combined Cycle Kentucky Pioneer Energy IGCC Demonstration Project Oxygen-blown, slagging fixed-bed gasifier with cold 400-MWe (net) 5-116 gas cleanup, fuel cell slipstream 2.0 MWe MCFC Pifion Pine IGCC Power Project Air-blown, fluidized-bed gasifier with hot gas cleanup 107 MWe (gross) 5-118 99-MWe (net) Tampa Electric Integrated Gasification Oxygen-blown, entrained-flow gasifier with hot and 313 MWe (gross) 5-120 Combined-Cycle Project cold gas cleanup and molten carbonate fuel cell (MCFC) 250-MWe (net) Wabash River Coal Gasification Oxygen-blown, two-stage entrained-flow gasifier with 296-MWe (gross); 5-122 262-MWe (net) Advanced Combustion/Heat Engines Healy Clean Coal Project Clean Coal Diesel Demonstration Project Advanced slagging combustor, spray dryer with sorbent recycle Coal-fueled diesel engine 50-MWe (nominal) 5-126 6.4-MWe (net) 5-128 Project Fact Sheets 5-9 Coal Processing for Clean Fuels Technology The coal processing category includes a range of technologies designed to produce high-energy-density, low-sulfur solid and clean liquid fuels, as well as systems to assist users in evaluating impacts of coal quality on boiler performance. In the case of the Custom Coals International project, advanced physical-cleaning techniques are applied to bituminous coal with an already high Btu content to remove the ash, which contains sulfur in the form of pyrite, an inorganic iron compound. A dense- medium cyclone using finely sized magnetite effective- ly separates 90 percent of the pyritic sulfur. But, because physical methods cannot remove the organi- cally bound sulfur, dense-medium-cyclone processed coals can only be considered compliance coals (meeting CAAA SO, requirements) if the organic sulfur content is very low. This processed compliance coal is called Carefree Coal™. For coals with signifi- cant organic sulfur content, sorbents and other addi- tives must be added to capture the sulfur released upon combustion and bring the coal into compliance. This second product is called Self-Scrubbing Coal™. The project is on hold. The Western SynCoal LLC’s advanced coal conversion process applies mostly physical-cleaning methods to low-Btu, low-sulfur subbituminous coals, primarily to remove moisture and secondarily to remove ash. The objective is to enhance the energy density of the already low-sulfur coal. Some conver- sion of the properties of the coal is required, however, to provide stability (prevent spontaneous combustion) in transport and handling. In the process, coal with 5,500 to 9,000 Btu/Ib, 25 to 40 percent moisture 5-10 Project Fact Sheets content, and 0.5 to 1.5 percent sulfur is converted to a 12,000 Btu/Ib product with 1.0 percent moisture and as low as 0.3 percent sulfur. The SynCoal” product is used at utility and industrial facilities. Project opera- tion was extended through 2001. The ENCOAL project, which completed opera- tional testing in July 1997, used mild gasification to convert low-Btu, low-sulfur subbituminous coal to a high-energy-density, low-sulfur solid product and a clean liquid fuel comparable to No. 6 fuel oil. Mild gasification is a pyrolysis process (heating in the absence of oxygen) performed at moderate tempera- tures and pressures. It produces condensable volatile hydrocarbons in addition to solids and gas. The condensable fraction is drawn off as a liquid product. Most of the gas is used to provide on-site energy requirements. The process solid is significantly beneficiated to produce an 11,000 Btu/Ib low-sulfur solid fuel. The demonstration plant processed 500 tons per day of subbituminous coal, and produced 250 tons per day of solid Process-Derived Fuel (PDF") and 250 barrels per day of Coal-Derived Liquids (CDL”). Both the solid and liquid fuels have undergone test burns at utility and industrial sites. The project was successful- ly completed. The liquid phase methanol (LPMEOH™) process being demonstrated is an 80,000 gallon/day indirect liquefaction process using synthesis gas from a coal gasifier. The unique aspect of the process is the use of an inert liquid to suspend the conversion catalyst. This removes the heat of reaction and eliminates the need for an intermediate water-gas shift conversion. Also addressed in the project are the load-following capabil- ity of the process by simulating application in an IGCC system, and fuel characteristics of the unrefined product. Since operations began in April 1997, approximately 43 million gallons of methanol have been produced and plant availability has exceeded 97 percent. Plant availability in 1998 and 1999 has exceeded 99.7 percent. ABB Combustion Engineering, Inc. and CQ Inc. have developed a personal computer software package that will serve as a predictive tool to assist utilities in selecting optimal quality coal for a specific boiler based on operational efficiency, cost, and environmen- tal considerations. Algorithms were developed and verified through comparative testing at bench, pilot, and utility scale. Six large-scale field tests were conducted at five separate utilities. The software has been released for commercial use. Exhibit 5-6 summarizes the process characteristics and size of the coal processing for clean fuels technolo- gies presented in more detail in the project fact sheets. Industrial Applications Technology Technologies applicable to the industrial sector address significant environmental issues and barriers associated with coal use in industrial processes. These technologies are directed at both continued coal use and introduction of coal use in various industrial sectors. One of the critical environmental concerns has to do with pollutant emissions resulting from producing coke from coal for use in steel making. Two approach- es to mitigate or eliminate this problem are being demonstrated. In one, about 40 percent of the coke is displaced through direct injection of granular coal into a blast furnace system. The coal is essentially burned in the blast furnace where the pollutant emissions are readily controlled (as opposed to first coking the coal). The other approach eliminates the need for coke making by using a direct iron-making process. In this Exhibit 5-6 CCT Program Coal Processing for Clean Fuels Technology Characteristics *Operated at 500 tons/day sorbent addition for bituminous coals Project Process Size Fact Sheet Development of the Coal Quality Expert™ Coal Quality Expert™ computer software Tested at 250-880-MWe 5-138 Advanced Coal Conversion Process Demonstration Advanced coal conversion process for upgrading 45 tons/hr 5-136 low-rank coals ENCOAL® Mild Coal Gasification Project Liquids-from-coal (LFC") mild gasification to 1,000 tons/day* 5-142 produce solid and liquid fuels Commercial-Scale Demonstration of the Liquid Phase Methanol Liquid phase process for methanol production from 80,000 gal/day 5-132 (LPMEOH™) Process coal-derived syngas Self-Scrubbing Coal™: An Integrated Approach to Clean Air Dense-medium cyclones with finely sized magnetic and 500 tons/hr 5-134 VY Western SynCoal Partnership’s advanced coal Y= The ENCOAL mild gasification plant near Gillette, WY conversion process plant in Colstrip, MT has produced over has operated 12,800 hours and processed approximately 260,000 tons of raw coal and produced over 120,000 tons of PDF® and 121,000 barrels of CDL®. 1.5 million tons of SynCoal” products. Y= The LPMEOH™ process produces over 80,000 gal/day of methanol, all of which is used by the Eastman Chemical Company in Kingsport, TN. Project Fact Sheets 5-11 process, raw coal is introduced into a reactor to produce reducing gas and heat for a unique reduction furnace; no coke is required. Excess reducing gas is cleaned and used to fuel a boiler for electric power generation. Because production costs are largely driven by fuel cost, coal is often the fuel of choice in cement production. Faced with the need to control SO, emissions and also to address growing solid waste management problems, industry sponsored the demon- stration of an innovative SO, scrubber. The successful- ly demonstrated Passamaquoddy Technology Recovery Scrubber™ uses cement kiln dust, otherwise discarded as waste, to control so, emissions, convert the sulfur and chloride acid gases to fertilizer, return the solid by- product as cement kiln feedstock, and produce distilled water. No new wastes are generated and cement kiln dust waste is converted to feedstock. This technology also has application for controlling pollutant emissions in paper production and waste-to-energy applications. In many industrial boiler applications, the relative- ly low, stable price of coal makes it an attractive substitute for oil and gas feedstock. However, draw- backs to conversion of oil- and gas-fired units to coal include addition of SO, and NO, controls, tube fouling, and the need for a coolant water circuit for the combus- tor. Oil- and gas-fired units are not high SO, or NO, emitters, use relatively tight tube spacing in the absence of potential ash fouling, and the flow of oil or gas cools the combustor, precluding the need for water cooling. For these reasons, the CCT Program demon- strated an advanced air-cooled, slagging combustor that could avoid these potential problems. The cyclone combustor stages introduction of air to control NO,, injects sorbent to control SO,, slags the ash in the combustor to prevent tube fouling, and uses air cooling to preclude the need for water circuitry. 5-12 Project Fact Sheets The pulse combustor to be demonstrated by ThermoChem has a wide range of applications. The technology can be used in many coal processes, including coal gasification and waste-to-energy applications. The cement kiln, slagging combustor projects, and granular-coal injection into a blast furnace projects are completed. The CPICOR™ and the ThermoChem projects are in the project definition and design phase, and construction phase, respectively. Exhibit 5-7 summarizes process characteristics and size for the industrial applications technologies presented in more detail in the project fact sheets. Project Fact Sheets The remainder of this document contains fact sheets for all 40 projects. Two types of facts sheets are provided: (1) a brief, two page overview for ongoing projects; and (2) an expanded four page summary for projects that have successfully completed operational testing. The expanded fact sheets for completed projects contain a summary of the major results from the demonstration as well as sources for obtaining further information, specifically, contact persons and key references. Information provided in the fact sheets includes the project participant and team members, project objectives, significant project features, process description, major milestones, progress (if ongoing) or summary of results (if completed), and commercial applications. A key to interpreting the milestone charts is provided in Exhibit 5-8. To prevent the release of project-specific information of a proprietary nature, process flow diagrams contained in the fact sheets are highly simplified, and are presented only as illustra- tions of the concepts involved in the demonstrations. The portion of the process or facility central to the demonstration is demarcated by the shaded area. An index to project fact sheets is provided in Exhibit 5-9. Projects are listed by application catego- ry. Ongoing projects in each category appear first followed by projects having completed operations. A shaded area distinguishes projects having completed operations from ongoing projects. Within these breakdowns, projects are listed alphabetically by participant. In addition, Exhibit 5-9 indicates the solicitation under which the project was selected; its status as of September 30, 1999; and the page number for each Fact Sheet. Exhibit 5-10 lists the projects alphabetically by participant and provides project, location, and page numbers. An appendix containing contact information for all of the projects is provided as Appendix D. A list of acronyms used in this document is provided as Appendix E. Exhibit 5-7 CCT Program Industrial Applications Technology Characteristics Project Process Size Fact Sheet Blast Furnace Granular-Coal Injection System Blast furnace granular-coal injection for reduction of coke use 7,000 net tons/day of hot 5-152 Demonstration Project metal/furnace Advanced Cyclone Combustor with Internal Advanced slagging combustor with staged combustion and sorbent 23 x 10° Btu/hr 5-156 Sulfur, Nitrogen, and Ash Control injection Clean Power from Integrated Coal/Ore Direct reduction iron-making process to eliminate coke; 170-MWe 5-148 Reduction (CPICOR™) combined-cycle power generation 3,300 tons/day of hot metal Cement Kiln Flue Gas Recovery Scrubber Cement kiln dust used to capture SO,; dust converted to feedstock; 1,450 tons/day of cement 5-160 and fertilizer and distilled water produced Pulse Combustor Design Qualification Test Advanced combustion using Manufacturing and Technology To be determined 5-150 Conversion International’s pulse combustor/gasifier VY Shown here is the Bethlehem Steel Corporation facility, which demonstrated the VY Shown here is the Cement Kiln Flue Gas Recovery Scrubber project’s crystallizer and injection of granulated coal directly into two blast furnaces at Burns Harbor, IN. condensor in foreground and flue gas condensor in background. Project Fact Sheets 5-13 Exhibit 5-8 Key to Milestone Charts in Fact Sheets Each fact sheet contains a bar chart that highlights major milestones—past and planned. The bar chart shows a project’s duration and indicates the time period for three general categories of project activities—preaward, design and construction, and operation. The key provided below explains what is in- cluded in each of these categories. Preaward Includes preaward briefings, negotiations, and other activities conducted during the period between DOE’s selection of the project and award of the cooper- ative agreement. ee Design and Construction Includes the NEPA process, permitting, design, procurement, construction, preoperational testing, and other activities conducted prior to the beginning of operation of the demonstration. MTF Memo-to-file CX Categorical exclusion EA — Environmental assessment EIS — Environmental impact statement ee] Operation Begins with start-up of operation and includes operational testing, data collection, analysis, evaluation, reporting, and other activities to complete the dem- onstration project. 5-14 Project Fact Sheets Exhibit 5-9 Project Fact Sheets by Application Category Project Participant Solicitation/Status Page Environmental Control Devices SO, Control Technologies 10-MWe Demonstration of Gas Suspension Absorption AirPol, Inc. CCT-III/completed 3/94 5-20 Confined Zone Dispersion Flue Gas Desulfurization Demonstration Bechtel Corporation CCT-III/completed 6/93 $-24 LIFAC Sorbent Injection Desulfurization Demonstration Project LIFAC-North America CCT-III/completed 6/94 5-28 Advanced Flue Gas Desulfurization Demonstration Project Pure Air on the Lake, L.P. CCT-II/completed 6/95 5-32 Demonstration of Innovative Applications of Technology for the CT-121 FGD Process — Southern Company Services, Inc. CCT-II/completed 12/94 5-36 NO, Control Technologies Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Southern Company Services, Inc. CCT-II/extended 5-42 Demonstration of Coal Reburning for Cyclone Boiler NO, Control The Babcock & Wilcox Company CCT-Il/completed 12/92 5-46 Full-Scale Demonstration of Low-NO, Cell Burner Retrofit The Babcock & Wilcox Company CCT-III/completed 4/93 5-50 Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler Energy and Environmental Research Corporation CCT-III/completed 1/95 5-54 Micronized Coal Reburning Demonstration for NO, Control New York State Electric & Gas Corporation CCT-IV/completed 9/99 5-58 Demonstration of Selective Catalytic Reduction Technology Southern Company Services, Inc. CCT-II/completed 7/95 5-62 for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Southern Company Services, Inc. CCT-II/completed 12/92 5-66 Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers Combined SO,/NO, Control Technologies Commercial Demonstration of the NOXSO SO,/NO, Removal Flue Gas Cleanup System NOXSO Corporation CCT-II/on hold 5-72 SNOX™ Flue Gas Cleaning Demonstration Project ABB Environmental Systems CCT-II/completed 12/94 5-74 SO,-NO,-Rox Box™ Flue Gas Cleanup Demonstration Project The Babcock & Wilcox Company CCT-I/completed 5/93 5-78 Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Energy and Environmental Research Corporation CCT-I/completed 10/94 5-82 LIMB Demonstration Project Extension and Coolside Demonstration McDermott Technology, Inc. CCT-I/completed 8/91 5-86 Milliken Clean Coal Technology Demonstration Project New York State Electric & Gas Corporation CCT-IV/completed 6/98 5-90 Integrated Dry NO,/SO, Emissions Control System Public Service Company of Colorado CCT-III/completed 12/96 5-94 Advanced Electric Power Generation Fluidized-Bed Combustion McIntosh Unit 4A PCFB Demonstration Project Lakeland, City of, Lakeland Electric CCT-III/design 5-100 McIntosh Unit 4B Topped PCFB Demonstration Project Lakeland, City of, Lakeland Electric CCT-V/design 5-102 JEA Large-Scale CFB Combustion Demonstration Project JEA CCT-I/design 5-104 Shaded area indicates projects having completed operations. Project Fact Sheets 5-15 Project Exhibit 5-9 (continued) Project Fact Sheets by Application Category Solicitation/Status Tidd PFBC Demonstration Project Nucla CFB Demonstration Project Integrated Gasification Combined-Cycle Kentucky Pioneer Energy IGCC Demonstration Project Pifion Pine IGCC Power Project Tampa Electric Integrated Gasification Combined-Cycle Project Wabash River Coal Gasification Repowering Project Advanced Combustion/Heat Engines Healy Clean Coal Project Clean Coal Diesel Demonstration Project Coal Processing for Clean Fuels Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process Self-Scrubbing Coal™: An Integrated Approach to Clean Air Advanced Coal Conversion Process Demonstration Development of the Coal Quality Expert™ ENCOAL® Mild Coal Gasification Project Industrial Applications Clean Power from Integrated Coal/Ore Reduction (CPICOR™) Pulse Combustor Design Qualification Test Blast Furnace Granular-Coal Injection System Demonstration Project Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Cement Kiln Flue Gas Recovery Scrubber Shaded area indicates projects having completed operations. Participant Page The Ohio Power Company CT-I/completed 3/95 5-106 Tri-State Generation and Transmission Association, Inc. CCT-I/completed 1/91 5-110 Kentucky Pioneer Energy, L.L.C. CCT-V/design 5-116 Sierra Pacific Power Company CCT-IV/operational 5-118 Tampa Electric Company CCT-III/operational 5-120 Wabash River Coal Gasification Repowering CCT-IV/operational 5-122 Project Joint Venture Alaska Industrial Development and Export Authority CCT-II]/operational 5-126 Arthur D. Little, Inc. CCT-V/construction 5-128 Air Products Liquid Phase Conversion Company, L.P CCT-II/operational 5-132 Custom Coals International CCT-IV/on hold 5-134 Western SynCoal LLC CT-I/operational 5-136 ABB Combustion Engineering, Inc. and CQ Ine. CCT-I/completed 12/95 5-138 ENCOAL Corporation CCT-III/completed 7/97 5-142 CPICOR™ Management Company L.L.C. CCT-V/design 5-148 ThermoChem, Inc. CCT-IV/design 5-150 Bethlehem Steel Corporation CCT-III/completed 9/99 5-152 Coal Tech Corporation CCT-I/completed 5/90 5-156 Passamaquoddy Tribe CCT-II/completed 9/93 5-160 5-16 Project Fact Sheets Exhibit 5-10 Project Fact Sheets by Participant Participant Project Location Page ABB Combustion Engineering, Inc. and CQ Inc. Development of the Coal Quality Expert™ Homer City, PA 5-138 ABB Environmental Systems SNOX™ Flue Gas Cleaning Demonstration Project Niles, OH 5-74 Air Products Liquid Phase Conversion Company, L.P. Commercial-Scale Demonstration of the Liquid-Phase Methanol (LPMEOH™) Kingsport, TN 5-132 Process AirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption West Paducah, KY 5-20 Alaska Industrial Development and Export Authority Healy Clean Coal Project Healy, AK 5-126 Arthur D. Little, Inc. Clean Coal Diesel Demonstration Project Fairbanks, AK 5-128 Babcock & Wilcox Company, The Demonstration of Coal Reburning for Cyclone Boiler NO, Control Cassville, WI 5-46 Babcock & Wilcox Company, The Full-Scale Demonstration of Low-NO, Cell Burner Retrofit Aberdeen, OH 5-50 Babcock & Wilcox Company, The SO,-NO,-Rox Box™ Flue Gas Cleanup Demonstration Project Dilles Bottom, OH 5-78 Bechtel Corporation Confined Zone Dispersion Flue Gas Desulfurization Demonstration Seward, PA 5-24 Bethlehem Steel Corporation Blast Furnace Granular-Coal Injection System Demonstration Project Burns Harbor, IN 5-152 Coal Tech Corporation Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Williamsport, PA 5-156 CPICOR™ Management Company L.L.C. Clean Power from Integrated Coal/Ore Reduction (CPICOR™) Vineyard, UT 5-148 CQ Inc. (see ABB Combustion Engineering and CQ Inc.) Custom Coals International Self-Scrubbing Coal™: An Integrated Approach to Clean Air Central City, PA 5-134 ENCOAL Corporation ENCOAL® Mild Coal Gasification Project Gillette, WY 5-142 Energy and Environmental Research Corporation Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Hennepin, IL 5-82 Springfield, IL Energy and Environmental Research Corporation Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler Denver, CO 5-54 JEA JEA Large-Scale CFB Combustion Demonstration Project Jacksonville, FL 5-104 Kentucky Pioneer Energy, L.L.C. Kentucky Pioneer Energy IGCC Demonstration Project Trapp, KY 5-116 Lakeland, City of, Lakeland Electric McIntosh Unit 4A PCFB Demonstration Project Lakeland, FL 5-100 Lakeland, City of, Lakeland Electric McIntosh Unit 4B Topped PCFB Demonstration Project Lakeland, FL 5-102 LIFAC-North America LIFAC Sorbent Injection Desulfurization Demonstration Project Richmond, IN 5-28 McDermott Technology, Inc. LIMB Demonstration Project Extension and Coolside Demonstration Loraine, OH 5-86 New York State Electric & Gas Corporation Micronized Coal Reburning Demonstration for NO, Control Lansing, NY 5-58 Project Fact Sheets 5-17 Exhibit 5-10 (continued) Project Fact Sheets by Participant Participant Project Location Page New York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project Lansing, NY 5-90 NOXSO Corporation Commercial Demonstration of the NOXSO SO,/NO, Removal Flue Gas On hold 5-72 Cleanup System Ohio Power Company, The Tidd PFBC Demonstration Project Brilliant, OH 5-106 Passamaquoddy Tribe Cement Kiln Flue Gas Recovery Scrubber Thomaston, ME 5-160 Public Service Company of Colorado Integrated Dry NO,/SO, Emissions Control System Denver, CO 5-94 Pure Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project Chesterton, IN 5-32 Sierra Pacific Power Company Pifion Pine IGCC Power Project Reno, NV 5-118 Southern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Coosa, GA 5-42 Southern Company Services, Inc. Demonstration of Innovative Applications of Technology for the CT-121 FGD Newnan, GA 5-36 Process Southern Company Services, Inc. Demonstration of Selective Catalytic Reduction Technology for the Control of Pensacola, FL 5-62 NO, Emissions from High-Sulfur, Coal-Fired Boilers Southern Company Services, Inc. 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Lynn Haven, FL 5-66 Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers Tampa Electric Company Tampa Electric Integrated Gasification Combined-Cycle Project Mulberry, FL 5-120 ThermoChem, Inc. Pulse Combustor Design Qualification Test Baltimore, MD 5-150 Tri-State Generation and Transmission Association, Inc. Nucla CFB Demonstration Project Nucla, CO 5-110 Wabash River Coal Gasification Repowering Wabash River Coal Gasification Repowering Project West Terre Haute, IN 5-122 Project Joint Venture Western SynCoal LLC Advanced Coal Conversion Process Demonstration Colstrip, MT 5-136 [| 5-18 — Project Fact Sheets Environmental Control Devices SO, Control Technologies ental Control Devices Program Ipdate 1999 5-19 Environmental Control Devices SO, Control Technology 10-MWe Demonstration of Gas Suspension Absorption Project completed. Participant AirPol, Inc. Additional Team Members FLS miljo, Inc. (FLS)—technology owner Tennessee Valley Authority—cofunder and site owner Location West Paducah, McCracken County, KY Technology FLS’ Gas Suspension Absorption (GSA) system for flue gas desulfurization (FGD) Plant Capacity/Production 10-MWe equivalent slipstream of flue gas from a 175-MWe wall-fired boiler Coal Western Kentucky bituminous— Peabody Martwick, 3.05% sulfur Emerald Energy, 2.61% sulfur Andalax, 3.06% sulfur Warrior Basin, 3.5% sulfur (used intermittently) Project Funding Total project cost $7,717,189 100% DOE 2,315,259 30 Participant 5,401,930 70 Project Objective To demonstrate the applicability of Gas Suspension Ab- sorption as an economic option for achieving Phase II CAAA SO, compliance on pulverized coal-fired boilers using high-sulfur coal. 5-20 Program Update 1999 HYDRATED LIME ! SLURRY TANK WATER BOILER COAL SUPPLY FLUE GAS FROM BOILER DRY ASH GAS SUSPENSION ABSORPTION REACTOR CYCLONE SEPARATOR ay | | RECYCLE PULSE JET BAGHOUSE eecrmos | ne Or ATor | —_ = TO ASH POND Technology/Project Description The GSA system consists of a vertical reactor in which flue gas comes into contact with suspended solids consist- ing of lime, reaction products, and fly ash. About 99% of the solids are recycled to the reactor via a cyclone while the exit gas stream passes through an electrostatic precipitator (ESP) or pulse jet baghouse (PJBH) before being released to the atmosphere. The lime slurry, pre- pared from hydrated lime, is injected through a spray nozzle at the bottom of the reactor. The volume of lime slurry is regulated with a variable-speed pump controlled by the measurement of the acid content in the inlet and outlet gas streams. The dilution water added to the lime slurry is controlled by on-line measurements of the flue gas exit temperature. A test program was structured to (1) optimize design of the GSA reactor for reduction of SO, emissions from boilers using high-sulfur coal, and (2) evaluate the envi- ronmental control capability, economic potential, and mechanical performance of GSA. A statistically designed parametric (factorial) test plan was developed involving six variables. Beyond evaluation of the basic GSA unit to control SO,, air toxics control tests were conducted, and the effectiveness of a GSA/ESP and GSA/PJBH to con- trol both SO, and particulates were tested. Factorial tests were followed by continuous runs to verify consistency of performance over time. Environmental Control Devices Calendar Year 1988 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4/41 1998 12/89 Preaward 10/90 10/92 Design and Construction Operation DOE selected project (CCT-IIl) 12/19/89 ( ) Operation initiated 10/92 NEPA process completed (MTF) 9/21/90 Preoperational tests initiated 9/92 Construction completed 9/92 Ground breaking/construction started 5/92 Cooperative agreement awarded 10/11/90 Design completed 12/91 A Project completed/final report issued 6/95 Operation completed 3/94 Environmental monitoring plan completed 10/2/92 Results Summary + GSA/ESP and GSA/PJBH removed 98% of the hydro- gen chloride (HCI), 96% of the hydrogen fluoride Environmental (HF), and 99% on more of most trace metals, except * Ca/S molar ratio had the greatest effect on SO, re- cadmium, antimony, mercury, and selenium. (GSA/PJBH removed 99+% of the selenium.) * The solid by-product was usable as low-grade cement. moval, with approach-to-saturation temperature next, followed closely by chloride content. + GSA/ESP achieved Operational + GSA/ESP lime utilization averaged 66.1% and GSA/PJBH averaged 70.5%. * The reactor achieved the same performance as a con- ventional spray dryer, but at one-quarter to one-third — 90% sulfur capture at a Ca/S molar ratio of 1.3 with 8 °F approach-to-saturation and 0.04% chloride, — 90% sulfur capture at a Ca/S molar ratio of 1.4 with 18 °F approach-to-saturation and 0.12% chloride, and . . the size. — 99.9+% average particulate removal efficiency. . + GSA generated lower particulate loading than a con- + GSA/PJBH achieved ventional spray dryer, enabling compliance with a — 96% sulfur capture at a Ca/S molar ratio of 1.4 with lower ESP efficiency. 18 °F h-to-saturati id 0.12% chloride, . ve . ee cies Special steels were not required in construction, and — 3-5% increase in SO, reduction relative to only a single spray nozzle is needed. GSA/ESP, and — 99.99+% average particulate removal efficiency. * High availability and reliability similar to other com- mercial applications were demonstrated, reflecting simple design. Environmental Control Devices Economic * Capital and levelized (15-year) costs for GSA installed in a 300-MWe plant using 2.6% sulfur coal are com- pared below to costs for a wet limestone scrubber with forced oxidation (WLFO scrubber). EPRI’s TAG™ cost method was used. Based on EPRI cost studies of FGD processes, the capital cost (1990$) for a conven- tional spray dryer was $172/kW. Capital Cost Levelized Cost (1990 $/kW) (mills/kWh) GSA—3 units at 149 10.35 50% capacity WLFO 216 13.04 Program Update 1999 5-21 Project Summary The GSA has a capability of suspending a high concentra- tion of solids, effectively drying the solids, and recirculat- ing the solids at a high rate with precise control. This results in SO, control comparable to that of wet scrubbers and high lime utilization. The high concentration of subsequent 14-day continuous run to evaluate the GSA/ PJBH configuration was performed under the same condi- tions as those of the 28-day run, except for adjustments in flyash injection rate from 1.5—1.0 gr/ft’ (actual). The 28-day run on the GSA/ESP system showed that the overall SO, removal efficiency averaged slightly more solids provides the sorbent/SO, contact area. The drying enables low approach-to-saturation tempera- ture and chloride usage. The rapid, precise, integral recycle system sustains the high solids concentration. The high lime utilization mitigates the largest operat- Exhibit 5-11 Variables and Levels Used in GSA Factorial Testing ing cost (lime) and further reduces costs by reducing the amount of by-product generated. The GSA is distinguished from the average spray dryer by its modest size, simple means of introducing reagent to the reactor, direct means of recirculating unused lime, and low reagent consumption. Also, injected slurry coats recycled solids, not the walls, avoiding corrosion and enabling use of carbon steel in fabrication. Environmental Performance Exhibit 5-11 lists the six variables used in the factorial Variable Level Approach-to-saturation temperature (°F) 8", 18, 28 Ca/S (moles Ca(OH),/mole inlet SO,) 1.00 and 1.30 Flyash loading (gr/ft’, actual) 0.50 and 2.0 Coal chloride level (%) 0.04 and 0.12 Flue gas flow rate (10° scfm) 14 and 20 Recycle screw speed (rpm) 30 and 45 “8 °F was only run at the low coal chloride level. tests and the levels at which they were applied. Inlet flue gas temperature was held constant at 320 °F. Factorial testing showed that lime stoichi- ometry had the greatest effect on SO, removal. Ap- Exhibit 5-12 GSA Factorial Testing Results proach-to-saturation temperature was the next most important factor, followed closely by chloride levels. Although an approach-to-saturation temperature of 8 °F was achieved without plugging the system, the test was conducted at a very low chloride level (0.04%). Because water evaporation rates decrease as chloride levels increase, an 18 °F approach-to-saturation tem- perature was chosen for the higher 0.12% coal chlo- ride level. Exhibit 5-12 summarizes key results from factorial testing. A 28-day continuous run to evaluate the GSA/ESP configuration was made with bituminous coals averaging 2.7% sulfur, 0.12% chloride levels, and 18 °F approach-to-saturation temperature. A 5-22. Program Update 1999 Ss —) ] O= 8 °F Approach - 0.04% Cl | Overall System SO, Removal (%) A | 60+ ------------ = Ae 18 °F Approach - 0.04% Cl} = a 18°F Approach - 0.12% Cl) 50 — ft —— 1 0.90 1.0 Ll 1.2 1.3 1.4 Fresh Lime Stoichiometry (moles Ca/mole SO, ) Note: All tests were conducted at a 320 °F inlet flue gas temperature. than 90%, very close to the set point of 91%, at an aver- age Ca/S molar ratio of 1.40-1.45 moles Ca(OH),/mole inlet SO,. The system was able to adjust rapidly to the surge in inlet SO, caused by switching to 3.5% sulfur Warrior Basin coal for a week. Lime utilization averaged 66.1%. The particulate removal efficiency averaged 99.9+% and emission rates were maintained below 0.015 1b/10° Btu. The 14-day run on the GSA/PJBH system showed that the SO, removal efficiency averaged more than 96% at an average Ca/S molar ratio of 1.34— 1.43 moles Ca(OH),/mole inlet SO,. Lime utilization averaged 70.5%. The particulate removal efficiency averaged 99.99+% and emission rates ranged from 0.001—0.003 1b/10° Btu. All air toxics tests were conducted with 2.7% sulfur, low-chloride coal with a 12 °F approach-to-saturation temperature and a high flyash loading of 2.0 gr/ft (ac- tual). The GSA/ESP arrangement indicated average removal efficiencies of greater than 99% for arsenic, barium, chromium, lead, and vanadium; somewhat less for manganese; and less than 99% for antimony, cad- mium, mercury, and selenium. The GSA/PJBH configu- ration showed 99+% removal efficiencies for arsenic, barium, chromium, lead, manganese, selenium, and vana- dium; with cadmium removal much lower and mercury removal lower than that of the GSA/ESP system. The removal of HCl and HF was dependent upon the utiliza- tion of lime slurry and was relatively independent of particulate control configuration. Removal efficiencies were greater than 98% for HCl and 96% for HF. Operational Performance Because the GSA system has suspended recycle solids to provide a contact area for SO, capture, multiple high- pressure atomizer nozzles or high-speed rotary nozzles to achieve uniform, fine droplet size are not required. Also, recycle of solids is direct and avoids recycling material in the feed slurry, which would necessitate expensive abra- sion-resistant materials in the atomizer(s). Environmental Control Devices The high heat and mass transfer characteristics of the GSA enable the GSA system to be significantly smaller than a conventional spray dryer for the same This makes retrofit feasible for space-confined plants and capacity—one-quarter to one-third the size. reduces installation cost. The GSA system slurry is sprayed on the recycled solids, not the reactor walls, avoiding direct wall contact and the need for corrosion- resistant alloy steels. Furthermore, the high concentra- tion of rapidly moving solids scours the reactor walls and mitigates scaling. The GSA system generates a significantly lower grain loading than a conventional spray dryer—2-S gr/ft? for GSA versus 6-10 gr/ft? for a spray dryer—enabling compliance even with lower ESP particulate removal efficiency. The GSA system pro- duces a solid by-product containing very low moisture. This material contains both fly ash and unreacted lime. With the addition of water, the by-product undergoes a pozzolanic reaction, essentially providing the charac- teristics of a low-grade cement. Economic Performance Using EPRI costing methods, which have been applied to 30 to 35 other FGD processes, economics were estimated for a moderately difficult retrofit of a 300-MWe boiler burning 2.6% sulfur coal. The design SO, removal effi- ciency was 90% at a lime feed rate equivalent to 1.30 moles of Ca/mole inlet SO,. Lime was assumed to be 2.8 times the cost of limestone. It was determined that (1) capital cost was $149/kW (19908) with three units at 50% capacity, and (2) levelized cost (15-year) was 10.35 mills/ kWh with three units at 50% capacity. A cost comparison run for a WLFO scrubber showed the capital and levelized costs to be $216/kW and 13.04 mills/kWh, respectively. The capital cost listed in EPRI cost tables for a conventional spray dryer at 300-MWe and 2.6% sulfur coal was $172/kW (1990$). Also, be- cause the GSA requires less power and has better lime utilization than a spray dryer, the GSA will have a lower operating cost. Environmental Control Devices A AirPol, Inc. successfully demonstrated the GSA system at TVA’s Center for Emissions Research. Commercial Applications The low capital cost, moderate operating cost, and high SO, capture efficiency make the GSA system particularly attractive as a CAAA compliance option for boilers in the 50- to 250-MWe range. Other major advantages include the modest space requirements comparable to duct injec- tion systems; high availability/reliability owing to design simplicity; and low dust loading, minimizing particulate upgrade costs. GSA market entry was significantly enhanced with the sale of a 50-MWe unit, worth $10 million, to the city of Hamilton, Ohio, subsidized by the Ohio Coal Develop- ment Office. A sale worth $1.3 million has been made to the U.S. Army for hazardous waste disposal. A GSA system has been sold to a Swedish iron ore sinter plant. Sales to Taiwan and India have a combined value of $5.5 million. Contacts Niels H. Kastrup, (281) 539-3400 FLS miljo, Inc. 100 Glennborough Houston, TX 77067 (281) 539-3411 (fax) Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, NETL, (412) 386-5991 References * 10-MWe Demonstration of Gas Suspension Absorp- tion Final Project Performance and Economics Report. Report No. DOE/PC/90542-T9. AirPol, Inc. June 1995. (Available from NTIS as DE95016681.) * 10-MW Demonstration of Gas Suspension Absorp- tion Final Public Design Report. Report No. DOE/PC/90542-T10. AirPol, Inc. June 1995. (Available from NTIS as DE960003270.) + SO, Removal Using Gas Suspension Absorption Topical Report No. 4. U.S. Depart- April 1995. Technology. ment of Energy and AirPol, Inc. 10-MWe Demonstration of the Gas Suspension Absorption Process at TVA’ Center for Emissions Research: Final Report. Report No. DOE/PC/ 90542-T10. Tennessee Valley Authority. March 1995. (Available from NTIS as DE96000327.) Program Update 1999 5-23 Environmental Control Devices SO, Control Technology Confined Zone Dispersion Flue Gas Desulfurization Demonstration Project completed. Participant Bechtel Corporation Additional Team Members Pennsylvania Electric Company—cofunder and host Pennsylvania Energy Development Authority—cofunder New York State Electric % Gas Corporation—cofunder Rockwell Lime Company—cofunder Location Seward, Indiana County, PA (Pennsylvania Electric Company’s Seward Station, Unit No. 5) Technology Bechtel Corporation’s in-duct, confined zone disper- sion flue gas desulfurization (CZD/FGD) process Plant Capacity/Production 73.5-MWe equivalent Coal Pennsylvania bituminous, 1.2—2.5% sulfur Project Funding Total project cost* $10,411,600 100% DOE 5,205,800 50 Participant 5,205,800 50 Project Objective To demonstrate SO, removal capabilities of in-duct CZD/ FGD technology; specifically, to define the optimum process operating parameters and to determine CZD/ * Additional project overrun costs were funded 100% by the participant for a final total project cost of $12,173,000. 5-24 Program Update 1999 BOILER WATER 2nd STAGE ELECTROSTATIC ELECTROSTATIC PRECIPITATOR PRECIPITATOR | DOLOMITIC CALCITIC LIME PULVERIZED AIR PREHEATER COAL——+ AIR ——*| SOLID WASTE STACK ] | SORBENT | | SLURRY | | SOLID WASTE TO DISPOSAL FGD’s operability, reliability, and cost-effectiveness during long-term testing and its impact on downstream operations and emissions. Technology/Project Description In Bechtel’s CZD/FGD process, a finely atomized slurry of reactive lime is sprayed into the flue gas stream be- tween the boiler air heater and the electrostatic precipita- tor (ESP). The lime slurry is injected into the center of the duct by spray nozzles designed to produce a cone of fine spray. As the spray moves downstream and expands, the gas within the cone cools and the SO, is quickly absorbed in the liquid droplets. The droplets mix with the hot flue gas, and the water evaporates rapidly. Fast drying precludes wet particle buildup in the duct and aids the flue gas in carrying the dry reaction products and the unreacted lime to the ESP. This project included injection of different types of sorbents (dolomitic and calcitic limes) with several atomizer designs using low- and high-sulfur coals to verify the effects on SO, removal and the capability of the ESP to control particulates. The demonstration was conducted at Pennsylvania Electric Company’s Seward Station in Seward, PA. One-half of the flue gas capacity of the 147-MWe Unit No. 5 was routed through a modified, longer duct between the first- and second-stage ESPs. Environmental Control Devices Calendar Year 1988 3 4/1 2 3 4/1 2 3 4/1 2 3 4 1993 1994 12/89 10/90 7/91 Preaward DOE selected project (CCT-IIl) 12/19/89 Design start 6/90 NEPA process completed (MTF) 9/90 Design and Construction 6/94 Operation Project completed/final report issued 6/94 Operation completed 6/93 Preoperational tests initiated 7/91 Operation initiated 7/91 Cooperative agreement awarded 10/90 Design completed 10/90 Construction completed 6/91 Environmental monitoring plan 6/12/91 Ground breaking/construction started 3/91 Results Summary . Environmental * Pressure-hydrated dolomitic lime proved to be a more effective sorbent than either dry hydrated calcitic lime or freshly slaked calcitic lime. * Sorbent injection rate was the most influential pa- rameter on SO, capture. Flue gas temperature was . the limiting factor on injection rate. For SO, capture efficiency of 50% or more, a flue gas temperature of 300 °F or more was needed. * Slurry concentration for a given sorbent did not in- crease SO, removal efficiency beyond a certain threshold concentration. + Testing indicated that SO, removal efficiencies of 50% or more were achievable with flue gas tempera- tures of 300-310 °F (full load), sorbent injection rate 7 of 52-57 gal/min, residence time of 2 seconds, and a . pressure-hydrated dolomitic-lime concentration of about 9%. Environmental Control Devices For operating conditions at Seward Station, data indicated that for 40-50% SO, removal, a 6-8% lime or dolomitic lime slurry concentration, and a sto- ichiometric ratio of 2—2.5 resulted in a 40-50% lime utilization rate. That is, 2-2.5 moles of CaO or CaO*MgO were required for every mole of SO, removed. Assuming 92% lime purity, 1.9-2.4 tons of lime was required for every ton of SO, removed. Operational About 100 ft of straight duct was required to assure the 2-second residence time needed for effective CZD/FGD operation. At Seward Station, stack opacity was not detrimentally affected by CZD/FGD. Availability of CZD/FGD was very good. Some CZD/FGD modification will be necessary to assure consistent SO, removal and avoid deposition of solids within the ductwork during upsets. Economic * Capital cost of a 500-MWe system operating on 4% sulfur coal and achieving 50% SO, reduction was estimated at less than $30/kW and operating cost at $300/ton of SO, removed (19948). Program Update 1999 5-25 Project Summary The principle of the CZD/FGD is to form a wet zone of slurry droplets in the middle of a duct confined in an envelope of hot gas be- tween the wet zone and the hot gas. The lime slurry reacts with part of the SO, in the gas and the reaction products dry to form solid particles. An ESP, downstream from the point of injection, captures the reaction products along with the fly ash entrained in the flue gas. CZD/FGD did not require a special reac- tor, simply a modification to the ductwork. Use of the commercially available Type S pressure-hydrated dolomitic lime reduced residence time requirements for CZD/FGD and enhanced sorbent utilization. The in- creased humidity of CZD/FGD processed flue gas enhanced ESP performance, elimi- nating the need for upgrades to handle the increased particulate load. Bechtel began its 18-month, two-part test program for the CZD process in July 1991, with the first 12 months of the test program consisting primarily of parametric testing and the last 6 months consisting of continuous operational testing. During the continuous operational test period, the system was operated under fully automatic control by the host utility boiler operators. The new atomizing nozzles were thoroughly tested both outside and inside the duct prior to testing. The SO, removal parametric test program, which began in October 1991, was completed in August 1992. Specific objectives were as follows: * Achieve projected SO, removal of 50% * Realize SO, removal costs of less than $300/ton + Eliminate negative effects on normal boiler operations without increasing particulate emissions and opacity The parametric tests included duct injection of atom- ized lime slurry made of dry hydrated calcitic lime, 5-26 Program Update 1999 A Bechtel’s demonstration showed that 50% SO, removal efficiency was possible using CZD/FGD technology. The extended duct into which lime slurry was injected is in the foreground. freshly slaked calcitic lime, and pressure-hydrated dolomitic lime. All three reagents remove SO, from the flue gas but require different feed concentrations of lime slurry for the same percentage of SO, removed. The most efficient removals and easiest to operate system were obtained using pressure-hydrated dolo- mitic lime. Environmental Performance Sorbent injection rate proved to be the most influential factor on SO, capture. The rate of injection possible was limited by the flue gas temperature. This impacted a portion of the demonstration when air leakage caused flue gas temperature to drop from 300-310 °F to 260-280 °F. At 300-310 °F, injection rates of 52-57 gal/min were possible and SO, reductions greater than 50% were achieved. At 260-280 °F, injection rates had to be dropped to 30-40 gal/min, resulting in a 15-30% drop in SO, removal efficiency. Slurry concentration for a given sorbent did not increase SO, removal efficiency beyond a certain threshold concentration. For example, with pressure-hydrated dolomitic lime, slurry concen- trations above 9% did not increase SO, capture effi- ciency. Parametric tests indicated that SO, removals above 50% are possible under the following conditions: flue gas temperature of 300-310 °F; boiler load of 145- to 147-MWe; residence time in the duct of 2 seconds; and lime slurry injection rate of 52-57 gal/min. Operational Performance The percentage of lime utilization in the CZD/FGD sig- nificantly affected the total cost of SO, removal. An analysis of the continuous operational data indicated that the percentage of lime utilization was directly dependent on two key factors: (1) percentage of SO, removed, and (2) lime slurry feed concentration. For operating conditions at Seward Station, data indicated that for 40-50% SO, removal, a 6-8% lime or dolomitic lime slurry concentration, and a stoichiometric ratio of 2—2.5 resulted in a 40-50% lime utilization rate. That is, 2~2.5 moles of CaO or CaO*MgO were required for every mole of SO, removed; or assuming 92% lime purity, 1.9—2.4 tons of lime were required for every ton of SO, removed. In summary, the demonstration showed the following results: + A 50% SO, removal efficiency with CZD/FGD was possible. Drying and SO, absorption required a residence time of 2 seconds, which required a long and straight hori- zontal gas duct of about 100 feet. * The fully automated system integrated with the power plant operation demonstrated that the CZD/FGD pro- cess responded well to automated control operation. However, modifications to the CZD/FGD were re- quired to assure consistent SO, removal and avoid deposition of solids within the gas duct during upsets. Environmental Control Devices + Availability of the system was very good. + At Seward Station, stack opacity was not detrimen- tally affected by the CZD/FGD system. Economic Performance The CZD/FGD process can achieve costs of $300/ton of SO, removed when operating a 500-MWe unit burning 4% sulfur coal. Based on a 500-MWe plant retrofitted with CZD/FGD for 50% SO, removal, the total capital cost is estimated to be less than $30/kW (1994$). Commercial Applications After the conclusion of the DOE-funded CZD/FGD dem- onstration project at Seward Station, the CZD/FGD sys- tem was modified to improve SO, removal during con- tinuous operation while following daily load cycles. Bechtel and the host utility, Pennsylvania Electric Com- pany, continued the CZD/FGD demonstration for an additional year. Results showed that CZD/FGD operation at SO, removal rates lower than 50% could be sustained over long periods without significant process problems. CZD/FGD can be used for retrofit of existing plants and installation in new utility boiler flue gas facilities to remove SO, from a wide variety of sulfur-containing coals. A CZD/FGD system can be added to a utility boiler with a capital investment of about $25—50/kW of installed capacity, or approximately one-fourth the cost of building a conventional wet scrubber. In addition to low capital cost, other advantages include small space require- ments, ease of retrofit, low energy requirements, fully automated operation, and production of only nontoxic, disposable waste. The CZD/FGD technology is par- ticularly well suited for retrofitting existing boilers, independent of type, age, or size. The CZD/FGD instal- lation does not require major power station alterations and can be easily and economically integrated into existing power plants. Environmental Control Devices Contacts Joseph T. Newman, Project Manager, (415) 768-1189 Bechtel Corporation P.O. Box 193965 San Francisco, CA 94119-3965 (415) 768-5420 (fax) Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, NETL, (412) 386-5991 References * Confined Zone Dispersion Project: Final Technical Report. Bechtel Corporation. June 1994. Confined Zone Dispersion Project: Public Design Report. Bechtel Corporation. October 1993. * Comprehensive Report to Congress on the Clean Coal Technology Program: Confined Zone Disper- sion Flue Gas Desulfurization Demonstration. Bechtel Corporation. Report No. DOE/FE-0203P. U.S. Department of Energy. September 1990. (Avail- able from NTIS as DE91002564.) A This photo shows the CZD/FGD lime slurry injector control system. Program Update 1999 5-27 Environmental Control Devices SO, Control Technology LIFAC Sorbent Injection Desulfurization Demonstration Project Project completed. Participant LIFAC-North America (a joint venture partnership between Tampella Power Corporation and ICF Kaiser Engineers, Inc.) Additional Team Members ICF Kaiser Engineers, Inc.—cofunder and project manager Tampella Power Corporation—cofunder Tampella, Ltd—technology owner Richmond Power and Light—cofunder and host utility Electric Power Research Institute—cofunder Black Beauty Coal Company—cofunder State of Indiana—cofunder Location Richmond, Wayne County, IN (Richmond Power % Light’s Whitewater Valley Station, Unit No. 2) Technology LIFAC’s sorbent injection process with sulfur capture in a unique, patented vertical activation reactor Plant Capacity/Production 60-M We Coal Bituminous, 2.0—-2.8% sulfur Project Funding Total project cost $21,393,772 100% DOE 10,636,864 50 Participants 10,756,908 50 5-28 Program Update 1999 LIMESTONE/ SORBENT INJECTION { AIR AIR COAL _, PREHEATER AIR- —+ DRY ASH ACTIVATION REACTOR ELECTROSTATIC PRECIPITATOR FAN STACK SORBENT = RECYCLE SOLID WASTE TO DISPOSAL Project Objective To demonstrate that electric power plants—especially those with space limitations and burning high-sulfur coals—can be retrofitted successfully with the LIFAC limestone injection process to remove 75-85% of the SO, from flue gas and produce a dry solid waste product for disposal in a landfill. Technology/Project Description Pulverized limestone is pneumatically blown into the upper part of the boiler near the superheater where it absorbs some of the SO, in the boiler flue gas. The lime- stone is calcined into calcium oxide and is available for capture of additional SO, downstream in the activation, or humidification, reactor. In the vertical chamber, water sprays initiate a series of chemical reactions leading to SO, capture. After leaving the chamber, the sorbent is easily separated from the flue gas along with the fly ash in the electrostatic precipitator (ESP). The sorbent mate- rial from the reactor and electrostatic precipitator are recirculated back through the reactor for increased effi- ciency. The waste is dry, making it easier to handle than the wet scrubber sludge produced by conventional wet limestone scrubber systems. The technology enables power plants with space limitations to use high-sulfur midwestern coals by provid- ing an injection process that removes 75-85% of the SO, from flue gas and produces a dry solid waste product suitable for disposal in a landfill. Environmental Control Devices Calendar Year 1988 1989 3 4/1 2 3 4/1 2 3 4 1 2 3 1998 12/89 11/90 Preaward | > Design and Construction | 9/92 | Operation initiated 9/92 Preoperational tests initiated 7/92 Environmental monitoring plan completed 6/12/92 Construction completed 6/92 Original design completed 7/91 Ground breaking/construction started 5/29/91 Cooperative agreement awarded 11/20/90 NEPA process completed (MTF) 10/2/90 DOE selected project (CCT-IIl)_ 12/19/89 Operation 4/98 t Project completed/final report issued 4/98 Operation completed 6/94 Results Summary Environmental + SO, removal efficiency was 70% at a calcium-to- sulfur (Ca/S) molar ratio of 2.0, approach-to-satura- tion temperature of 7-12 °F, and limestone fineness of 80% minus 325 mesh. + SO, removal efficiency with limestone fineness of 80% minus 200 mesh was 15% lower at a Ca/S molar ratio of 2.0 and 7-12 °F approach-to-saturation temperature. + The four parameters having the greatest influence on sulfur removal efficiency were limestone fine- ness, Ca/S molar ratio, approach-to-saturation temperature, and ESP ash recycle rate. * ESP ash recycle rate was limited in the demonstration system configuration. Increasing the recycle rate and sustaining a 5 °F approach-to-saturation temperature were projected to increase SO, removal efficiency to 85% at a Ca/S molar ratio of 2.0 (fine limestone). Environmental Control Devices ESP efficiency and operating levels were essentially unaffected by LIFAC operation during steady-state operation. Fly and bottom ash were dry and readily disposed of at a local landfill. The quantity of additional solid waste can be determined by assuming that approxi- mately 4.3 tons of limestone is required to remove 1.0 ton of SO,. Operational When operating with fine limestone (80% minus 325 mesh), the soot-blowing cycle had to be reduced from 6.0 to 4.5 hours. Automated programmable logic and simple design make the LIFAC system easy to operate in startup, shutdown, or normal duty cycles. The amount of bottom ash increased slightly, but there was no negative impact on the ash-handling system. Economic Capital cost—$66/kW for two LIFAC reactors (300-M We); $76/kW for one LIFAC reactor (150-MWe); $99/kW for one LIFAC reactor (65-MWe) (19948). Operating cost—$65/ton of SO, removal, assuming 75% SO, capture, Ca/S molar ratio of 2.0, limestone composed of 95% CaCO,, and costing $15/ton. Program Update 1999 5-29 Project Summary The LIFAC technology was designed to enhance the effectiveness of dry sorbent injection systems for SO, control and to maintain the desirable aspects of low capi- tal cost and compactness for ease of retrofit. Furthermore, limestone was used as the sorbent (about 1/3 of the cost of lime) and a sorbent recycle system was incorporated to reduce operating costs. The process evaluation test plan was composed of five distinct phases each having its own objectives. These tests were as follows: * Baseline tests characterized the operation of the host boiler and associated subsystems prior to LIFAC operations. * Parametric tests were designed to evaluate the many possible combinations of LIFAC process parameters and their effect on SO, removal. * Optimization tests were performed after the parametric tests to evaluate the reliability and operability of the LIFAC process over short, continuous operating periods. * Long-term tests were performed to demonstrate LIFAC’s performance under commercial operating conditions. * Post-LIFAC tests involved repeating the baseline test to identify any changes caused by the LIFAC system. The coals used during the demonstration varied in sulfur content from 1.4-2.8%. However, most of the testing was conducted with the higher sulfur coals (2.0-2.8% sulfur). Environmental Performance During the parametric testing phase, the numerous LIFAC process values and their effects on sulfur removal effi- ciency were evaluated. The four major parameters having the greatest influence on sulfur removal efficiency were limestone fineness Ca/S molar ratio, reactor bottom tem- perature (approach-to-saturation), and ESP ash recycling rate. Total SO, capture was about 15% better when in- jecting fine limestone (80% minus 325 mesh) than it was with coarse limestone (80% minus 200 mesh). 5-30 Program Update 1999 While injecting the fine limestone, the soot blowing frequency had to be increased from 6-hour to 4.5-hour cycles. The coarse-quality limestone did not affect soot blowing but was found to be more abrasive on the feed and transport hoses. Parametric tests indicated that a 70% SO, reduction was achievable with a Ca/S molar ratio of 2.0. ESP ash containing unspent sorbent and fly ash was recycled from the ESP hoppers back into the reactor inlet duct work. Ash recycling is essential for efficient SO, capture. The large quantity of ash removed from the LIFAC reactor bottom and the small size of the ESP hoppers limited the ESP ash recycling rate. As a result, the amount of mate- rial recycled from the ESP was approximately 70% less than had been anticipated. However, this low recycling rate was found to affect SO, capture. During a brief test, it was found that increasing the recycle rate by 50% re- sulted in a 5% increase in SO, removal efficiency. It was estimated that if the reactor bottom ash is recycled along with ESP ash, while sustaining a reactor temperature of 5 °F above saturation temperature, an SO, reduction of 85% could be maintained. Operational Performance Optimization testing began in March 1994 and was fol- lowed by long-term testing in June 1994. The boiler was operated at an average load of 60-MWe during long-term testing, although it fluctuated according to power de- mand. The LIFAC process automatically adjusted to boiler load changes. A Ca/S molar ratio of 2.0 was se- lected to attain SO, reductions above 70%. Reactor bot- tom temperature was about 5 °F higher than optimum to avoid ash buildup on the steam reheaters. Atomized water droplet size was smaller than optimum for the same reason. Other key process parameters held constant dur- ing the long-term tests included the degree of humidifica- tion, grind size of the high-calcium-content limestone, and recycle of spent sorbent from the ESP. Long-term testing showed that SO, reductions of 70% or more can be maintained under normal boiler A The LIFAC system successfully demonstrated at Whitewater Valley Station Unit No. 2 is being retained by Richmond Power % Light for commercial use with high- sulfur coal. There are 10 full-scale LIFAC units in Canada, China, Finland, Russia, and the United States. operating ranges. Stack opacity was low (about 10%) and ESP efficiency was high (99.2%). The amount of boiler bottom ash increased slightly during testing, but there was no negative impact on the power plant’s bottom and flyash removal system. The solid waste generated was a mixture of fly ash and calcium compounds and was readily disposed of at a local landfill. The LIFAC system proved to be highly operable because it has few moving parts and is simple to operate. Environmental Control Devices A The top of the LIFAC reactor is shown being lifted into place. During 2,800 hours of operation, long-term testing showed that SO, reductions of 70% or more could be sustained under normal boiler operation. The process can be easily shut down and restarted. The process is automated by a programmable logic system that regulates process control loops, interlocking, startup, shutdowns, and data collection. The entire LIFAC pro- cess was easily managed via two personal computers located in the host utility’s control room. Environmental Control Devices Economic Performance The economic evaluation indicated that the capital cost . of a LIFAC installation is lower than for either a spray dryer or wet scrubber. Capital costs for LIFAC technol- ogy vary, depending on unit size and the quantity of reactors needed: * $99/kW for one LIFAC reactor at Whitewater Valley . Station (65-MWe) (1994$), * $76/kW for one LIFAC reactor at Shand Station = (150-MWe), and * $66/kW for two LIFAC reactors at Shand Station (300-MWe). Crushed limestone accounts for about one-half of LIFAC’s operating costs. LIFAC requires 4.3 tons of limestone to remove 1.0 ton of SO,, assuming 75% SO, capture, a Ca/S molar ratio of 2.0, and limestone contain- ing 95% CaCO,. Assuming limestone costs of $15/ton, LIFAC’s operating cost would be $65/ton of SO, removed. Commercial Applications There are 10 full-scale LIFAC units in operation in Canada, China, Finland, Russia, and the United States. The LIFAC system at Richmond Power % Light is the first to be applied to a power plant using high-sulfur (2.0— 2.9%) coal. The LIFAC system is being retained by Rich- mond Power % Light at Whitewater Valley Station, Unit No. 2. The other LIFAC installations on power plants are using bituminous and lignite coals having lower sulfur contents (0.6-1.5%). Contacts Jim Hervol, Project Manager, (412) 497-2235 ICF Kaiser Engineers, Inc. Gateway View Plaza 1600 West Carson Street Pittsburgh, PA 15219-1031 (412) 497-2235 (fax) Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, NETL, (412) 386-5991 References LIFAC Sorbent Injection Desulfurization Demon- Final Report, Vol. II: Project Performance and Economics. LIFAC-North America. February 1998. (Available from NTIS as DE96004421.) “LIFAC Nearing Marketability.” Clean Coal Today. Report No. DOE/FE-0215P-21. Spring 1996. Viiala, J., et al. “Commercialization of the LIFAC Sorbent Injection Process in North America.” Third stration Project. Annual Clean Coal Technology Conference: Techni- cal Papers. September 1994. Comprehensive Report to Congress on the Clean Coal LIFAC Sorbent Injection Desulfurization Demonstration Project. LIFAC- North America. Report No. DOE/FE-0207P. U.S. Department of Energy, October 1990. (Available from NTIS as DE91001077.) Technology Program: Program Update 1999 5-31 Environmental Control Devices SO, Control Technology Advanced Flue Gas Desulfurization Demonstration Project Project completed. Participant Pure Air on the Lake, L.P. (a subsidiary of Pure Air, which is a general partnership between Air Products and Chemicals, Inc. and Mitsubishi Heavy Industries America, Inc.) Additional Team Members Northern Indiana Public Service Company—cofunder and host Mitsubishi Heavy Industries, Ltd.—process designer Stearns-Roger Division of United Engineers and Con- structors—facility designer Air Products and Chemicals, Inc.—constructor and operator Location Chesterton, Porter County, IN (Northern Indiana Public Service Company’s Bailly Generating Station, Unit Nos. 7 and 8) Technology Pure Air’s advanced flue gas desulfurization (AFGD) process Plant Capacity/Production 528-MWe Coal Bituminous, 2.0-4.5% sulfur Project Funding Total project cost $151,707,898 100% DOE 63,913,200 42 Participant 87,794,698 58 PowerChip is a registered trademark of Pure Air on the Lake, L.P. 5-32 Program Update 1999 WASTEWATER ELECTROSTATIC EVAPORATOR = _PRECIPITATOR HOT FLUE GAS OVER FLOW ABSORBER | HEADERS ~~~» MIST ELIMINATOR ABSORBER ie RECIRCULATION AIR OPEN GRID ' Lee { | GYPSUM ° | CENTRIFUGE A STACK SYSTEM f a gS Ss WATER GYPSUM ati ‘AIR DRY ROTARY LIMESTONE —s spaRnGER INJECTION SLAKED TO WASTEWATER UME TREATMENT Project Objective To reduce SO, emissions by 95% or more at approxi- mately one-half the cost of conventional scrubbing tech- nology, significantly reduce space requirements, and create no new waste streams. Technology/Project Description Pure Air built a single SO, absorber for a 528-MWe power plant. Although the largest capacity absorber module of its time in the United States, space require- ments were modest because no spare or backup absorber modules were required. The absorber performed three functions in a single vessel: prequenching, absorbing, and oxidation of sludge to gypsum. Additionally, the ab- sorber was of a co-current design, in which the flue gas and scrubbing slurry move in the same direction and at a relatively high velocity compared to that in conventional scrubbers. These features all combined to yield a state-of- the-art SO, absorber that was more compact and less expensive than contemporary conventional scrubbers. Other technical features included the injection of pulverized limestone directly into the absorber, a device called an air rotary sparger located within the base of the absorber, and a novel wastewater evaporation system. The air rotary sparger combined the functions of agitation and air distribution into one piece of equipment to facili- tate the oxidation of calcium sulfite to gypsum. Pure Air also demonstrated a unique gypsum agglomeration process, PowerChip*, to significantly enhance handling characteristics of adsorbed flue gas desulfurization (AFGD)-derived gypsum. Environmental Control Devices Calendar Year 1988 1989 1990 3 4)1 2 3 4 1 2 3 4 1 2 3 1998 9/88 12/89 Preaward DOE selected project (CCT-Il) 9/28/88 Design and Construction Operation Design completed 9/92 Construction completed 9/92 Operation initiated 6/92 Preoperational tests initiated 3/92 Environmental monitoring plan completed 1/31/91 NEPA process completed (EA) 4/16/90 Ground breaking/construction started 4/20/90 Cooperative agreement awarded 12/20/89 | Project completed/final report issued 6/96 Operation completed 6/95 Results Summary Environmental AFGD design enabled a single 600-MWe absorber module without spares to remove 95% or more SO, at availabilities of 99.5% when operating with high- sulfur coals. Wallboard-grade gypsum was produced in lieu of solid waste, and all gypsum produced was sold commercially. The wastewater evaporation system (WES) mitigated expected increases in wastewater generation associated with gypsum production and showed the potential for achieving zero wastewater discharge (only a partial- capacity WES was installed). PowerChip® increased the market potential for AFGD- derived gypsum by cost effectively converting it to a product with the handling characteristics of natural rock gypsum. Environmental Control Devices Air toxics testing established that all acid gases were effectively captured and neutralized by the AFGD. Trace elements largely became constituents of the solids streams (bottom ash, fly ash, gypsum product). Some boron, selenium, and mercury passed to the stack gas in a vapor state. Operational AFGD use of co-current, high-velocity flow; integra- tion of functions; and a unique air rotary sparger proved to be highly efficient, reliable (to the exclusion of requiring a spare module), and compact. The com- pactness, combined with no need for a spare module, significantly reduced space requirements. The own-and-operate contractual arrangement whereby Pure Air took on the turnkey, financing, operating, and maintenance risks through performance guarantees was successful. Economic * Capital costs and space requirements for AFGD were about half those of conventional systems. Program Update 1999 5-33 Project Summary The project proved that single absorber modules of ad- vanced design could process large volumes of flue gas and provide the required availability and reliability with- out the usual spares. The major performance objectives were met. Over the 3-year demonstration, the AFGD unit accu- mulated 26,280 hours of operation with an availability of 99.5%. Approximately 237,000 tons of SO, were re- moved, with capture efficiencies of 95% or more, and over 210,000 tons of salable gypsum were produced. The AFGD continues in commercial service, which includes sale of all by-product gypsum to U.S. Gypsum’s East Chicago, Indiana wallboard production plant. Environmental Performance Testing over the 3-year period clearly established that AFGD operating within its design parameters (without additives) could consistently achieve 95% SO, reduction or more with 2.0-4.5% sulfur coals. The design range for the calcium-to-sulfur stoichiometric ratio was 1.01—1.07, with the upper value set by gypsum purity requirements (i.¢., amount of unreacted reagent allowed in the gypsum). Another key control parameter was the ratio L/G, which is the amount of reagent slurry injected into the absorber grid (L) to the volume of flue gas (G). The design L/G range was 50-128 gal/1,000 ft’. The lower end was determined by solids settling rates in the slurry and the requirement for full wetting of the grid packing. The high end was determined by where perfor- mance leveled out. Five coals with differing sulfur contents were se- lected for parametric testing to examine SO, removal efficiency as a function of load, sulfur content, stoichio- metric ratio, and L/G. Loads tested were 33%, 67%, and 100%. High removal efficiencies, well above 95%, were possible at loads of 33% and 67% with low to moderate stoichiometric ratio and L/G settings, even for 4.5% sulfur coal. Exhibit 5-13 summarizes the results of para- metric testing at full load. 5-34 Program Update 1999 Exhibit 5-13 (100% Boiler Load) SO, Removal Performance transport and whether they can handle the gypsum by- product. For these reasons, PowerChip® technology was demonstrated as part of the project. This technology uses 100 100 & & 2 $ Stoichiometric Ratio 1.045 @ Sulfur Content 2.25% © Sulfur Content 2.75% @ Sulfur Content 4.0%. © Sulfur Content 4.5% SO, Removal Efficiency (%) SO, Removal Efficiency (%) g 8 ~% a Liquid-to-Gas Ratio: 76% of Design = Sulfur Content © Sulfur Content © Sulfur Content © Sulfur Content 4.5% a compression mill to con- vert the highly cohesive . AFGD gypsum cake into a flaked product with handling characteristics equivalent to natural rock gypsum. The 2.25% process avoids use of bind- 2.75% . : 4.0%. ers, pre-drying or pre-calcin- ing normally associated with 80 50 60 70 80 90 100 1.010 1.025 Absorber Recirculation Rate (Moles Calcium/Mole SO, Removed) briquetting, and is 30-55% cheaper at $2.50-$4.10/ton. Air toxics testing estab- 1.040 1.055 1.070 1.085 1.100 Stoichiometric Ratio In the AFGD process, chlorides that would have been released to the air are captured but potentially be- come a wastewater problem. This was mitigated by the addition of the WES, which takes a portion of the waste- water stream with high chloride and sulfate levels and injects it into the ductwork upstream of the ESP. The hot flue gas evaporated the water and the dissolved solids were captured in the ESP. Problems were experienced early on, with the WES nozzles failing to provide ad- equate atomization, and plugging as well. This was re- solved by replacing the original single-fluid nozzles with dual-fluid systems employing air as the second fluid. Commercial-grade gypsum quality (95.6-99.7%) was maintained throughout testing, even at the lower sulfur concentrations where the ratio of fly ash to gypsum in- creases due to lower sulfate availability. The primary importance of producing a commercial-grade gypsum is avoidance of the environmental and economic conse- quences of disposal. Marketability of the gypsum is dependent upon whether users are in range of economic lished that all acid gases are effectively captured and neutralized by the AFGD. Trace elements largely become constituents of the solids streams (bottom ash, fly ash, gypsum product). Some boron, selenium, and mercury pass to the stack gas in a vapor state. Operational Performance Availability over the 3-year operating period averaged 99.5% while maintaining an average SO, removal effi- ciency of 94%. This was attributable to the simple, effec- tive design and an effective operating/maintenance phi- losophy. Modifications were also made to the AFGD system. An example was the implementation of new alloy technology, C-276 alloy over carbon steel clad material, to replace alloy wallpaper construction within the ab- sorber tower wet/dry interface. Also, use of co-current rather than conventional counter-current flow resulted in lower pressure drops across the absorber and afforded the flexibility to increase gas flow without an abrupt drop in removal efficiency. AFGD SO, capture efficiency with limestone was comparable to that in wet scrubbers using Environmental Control Devices lime, which is far more expensive. The 24-hour power consumption was 5,275 kW, or 61% of expected con- sumption, and water consumption was 1,560 gal/min, or 52% of expected consumption. Economic Performance Exhibit 5-14 summarizes capital and levelized current dollar cost estimates for nine cases with varying plant capacity and coal sulfur content. A capacity factor of 65% and a sulfur removal efficiency of 90% were assumed. The calculation of levelized cost followed guidelines established in EPRI’s Technical Assessment Guide™. The incremental benefits of the own-and-operate arrangement, by-product utilization, and emission allow- ances were also evaluated. Exhibit 5-15 depicts the rela- tive costs of a hypothetical 500-MWe generating unit in the Midwest burning 4.3% sulfur coal with a base case conventional FGD system and four incremental cases. The horizontal lines in Exhibit 5-15 show the range of costs for a fuel-switching option. The lower bar is the cost of fuel delivered to the hypothetical midwest unit and the upper bar allows for some plant modifications to accommodate the compliance fuel. Commercial Applications AFGD is positioned well to compete in the pollution control arena of 2000 and Estimated Costs for an AFGD System (1995 Current Dollars) technology, e.g., in materials and components, should lower costs for AFGD. The own-and-operate business approach has done much to mitigate risk on the part of prospective users. High SO, capture efficiency places an AFGD user in the possible position to trade allowances or apply credits to other units within the utility. WES and PowerChip® mitigate or eliminate otherwise serious envi- ronmental concerns. AFGD effectively deals with hazard- ous air pollutants. The project received Power magazine’s 1993 Power- plant Award and the National Society of Professional Engineers’ 1992 Outstanding Engineering Achievement Award. Contacts Tim Roth, (610) 481-6257 Pure Air on the Lake, L.P. c/o Air Products and Chemicals, Inc. 7201 Hamilton Boulevard Allentown, PA 18195-1501 (610) 481-5820 (fax) Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, NETL, (412) 386-5991 Exhibit 5-14 beyond. AFGD has Cases: 1 2 3 4 5 6 7 8 9 markedly reduced Plant size (MWe) 100 100 ~=100 +» 300-300-300: 500 500-500 cost and demon- Coal sulfur content (%) 1S 3.0 45S 8 SS 8S strated the ability © | Ca tat cost (S/kW) 193 210-227, 86S compete with fuel ; itchi d Levelized cost ($/ton SO,) oui ing uncer 15-year life 1,518 840 603 720 401 294 536 302 223 certain circum- 20-year life 1527 846 607 716 399 294 531 300 223 stances even with a Levelized cost (mills/kWh) first-generation 15-year life 16.39 18.15 19.55 7.78 8.65 9.54 5.79 6.52 7.24 20-year life 16.49 18.28 19.68 7.73 862 9.52 5.74 648 7.21 system. Advances in Environmental Control Devices Exhibit 5-15 Flue Gas Desulfurization Economics §/Ton SO, 400 Plant Modifications 12 350 Delivered Fuel 250 08 200 06 150 04 100 A B c D E 500-MWe plant, 30-yr levelized costs, allowance value of $300/ton Incremental cases: A—Conventional FGD (EPRI model) B—AFGD, own-and-operate arrangement C—Adds gypsum sales D—Adds emission allowance credits at $300/ton, for 90% SO, removal E—Increases SO, removal to 95% References * Advanced Flue Gas Desulfurization (AFGD) Dem- Final Technical Report, Vol. II: Project Performance and Economics. Pure Air on the Lake, L.P. April 1996. (Available from NTIS as DE96050313.) + Advanced Flue Gas Desulfurization Project: Public Design Report. Pure Air on the Lake, L.P. March 1990. onstration Project. + Summary of Air Toxics Emissions Testing at Sixteen Utility Power Plants. Prepared by Burns and Roe Services Corporation for U.S. Department of Energy, Pittsburgh Energy Technology Center. July 1996. Program Update 1999 5-35 Environmental Control Devices SO, Control Technology Demonstration of Innovative Applications of Technology for the CT-121 FGD Process Project completed. Participant Southern Company Services, Inc. Additional Team Members Georgia Power Company—host Electric Power Research Institute—cofunder Radian Corporation—environmental and analytical consultant Ershigs, Inc.—fiberglass fabricator Composite Construction and Equipment—fiberglass sustainment consultant Acentech—flow modeling consultant Ardaman—gypsum stacking consultant University of Georgia Research Foundation— by-product utilization studies consultant Location Newnan, Coweta County, GA (Georgia Power Company’s Plant Yates, Unit No. 1) Technology Chiyoda Corporation’s Chiyoda Thoroughbred-121 (CT-121) advanced flue gas desulfurization (FGD) process Plant Capacity/Production 100-MWe Coal Illinois No. 5 % No. 6 blend, 2.4% sulfur Compliance, 1.2% sulfur Jet Bubbling Reactor is a registered trademark of the Chiyoda Corp. 5-36 Program Update 1999 ELECTROSTATIC PRECIPITATOR BOILER FLY ASH aac ! | QUENCH ZONE DUCT REACTION ZONE AR SPARGER PIPE + LIMESTONE SLURRY AIR SPARGER AGITATOR y Ap “as ~ GYPSUM STACK “COLLECTION POND Project Funding Total project cost DOE Participant $43,074,996 100% 21,085,211 49 21,989,785 51 Project Objective To demonstrate 90% SO, control at high reliability with and without simultaneous particulate control; to evaluate use of fiberglass-reinforced plastic (FRP) vessels to elimi- nate flue gas reheat and spare absorber modules; and to evaluate use of gypsum to reduce waste manage- ment costs. Technology/Project Description The project demonstrated the CT-121 FGD process, which uses a unique absorber design known as the Jet Bubbling Reactor® (JBR). The process combines lime- stone FGD reaction, forced oxidation, and gypsum crystallization in one process vessel. The process is mechanically and chemically simpler than conventional FGD processes and can be expected to exhibit lower cost characteristics. The flue gas enters underneath the scrubbing solu- tion in the JBR. The SO, in the flue gas is absorbed and forms calcium sulfite (CaSO,). Air is bubbled into the bottom of the solution to oxidize the calcium sulfite to form gypsum. The slurry is dewatered in a gypsum stack, which involves filling a diked area with gypsum slurry. Gypsum solids settle in the diked area by gravity, and clear water flows to a retention pond. The clear water from the pond is returned to the process. Environmental Control Devices Calendar Year 1988 3 1 Preaward Environmental monitoring plan completed 12/18/90 NEPA process completed (EA) 8/10/90 DOE selected project (CCT-Il) 9/28/88 started 8/23/90 Ground breaking/construction Design and Construction Operation initiated 10/92 Construction completed 10/92 Design completed 9/92 Preoperational tests initiated 5/92 Cooperative agreement awarded 4/2/90 Operation Project completed/final report issued 10/99* Operation completed 12/94 *Projected date “Years omitted Results Summary : Environmental * Over 90% SO, removal efficiency was achieved at SO, inlet concentrations of 1,000-3,500 ppm with . limestone utilization over 97%. + JBR achieved particulate removal efficiencies of 97.7-99.3% for inlet mass loadings of 0.303— ° 1.392 Ib/10° Btu over a load range of 50—100-MWe. + Capture efficiency was a function of particle size: — >10 microns—99% capture — 1-10 microns—90% capture — 0.5-1 micron—negligible capture — <0.5 micron—90% capture + Hazardous air pollutant (HAP) testing showed greater than 95% capture of hydrogen chloride (HCI) and hydrogen fluoride (HF) gases, 80-98% capture of most trace metals, less than 50% capture of mercury and cadmium, and less than 70% capture of selenium. Environmental Control Devices Gypsum stacking proved effective for producing wallboard/cement-grade gypsum. Operational FRP-fabricated equipment proved durable both structurally and chemically, eliminating the need for a flue gas prescrubber and reheat. FRP construction combined with simplicity of de- sign resulted in 97% availability at low ash loadings and 95% at high ash loadings, precluding the need for a spare reactor module. Simultaneous SO, and particulate control were achieved at flyash loadings reflective of an electro- static (ESP) with marginal performance. Economic Final results are not yet available. However, elimina- tion of the need for flue gas prescrubbing, reheat, and spare module requirement should result in capital requirements far below those of contemporary conven- tional FGD systems. Program Update 1999 5-37 Project Summary The CT-121 process differs from the more common spray tower type of flue gas desulfurization systems in that a single process vessel is used in place of the usual spray tower/reaction tank/thickener arrangement. Pumping of reacted slurry to a gypsum transfer tank is intermittent. This allows crystal growth to proceed essentially uninter- rupted resulting in large, easily dewatered gypsum crys- tals (conventional systems employ large centrifugal pumps to move reacted slurry causing crystal attrition and secondary nucleation). The demonstration spanned 27 months, including startup and shakedown, during which approximately 19,000 hours were logged. Exhibit 5-16 summarizes operating statistics. Elevated particulate loading included a short test with the electrostatic precipitator (ESP) com- pletely deenergized, but the long-term testing was con- ducted with the ESP partially deenergized to simulate a more realistic scenario, i.e., a CT-121 retrofit to a boiler with a marginally performing particulate collection de- vice. The SO, removal efficiency was measured under five different inlet concentrations with coals averaging 2.4% sulfur and ranging from 1.2— 4.3% sulfur (as burned). Operating Performance Use of FRP construction proved very successful. Because their large size precluded shipment, the JBR and lime- stone slurry storage tanks were constructed on site. Ex- cept for some erosion experienced at the JBR inlet transi- tion duct, the FRP-fabricated equipment proved to be durable both structurally and chemically. Because of the high corrosion resistance, the need for a flue gas prescrubber to remove chlorides was eliminated. Simi- larly, the FRP-constructed chimney proved resistant to the corrosive condensates in wet flue gas, precluding the need for flue gas reheat. Availability of the CT-121 scrubber during the low ash test phase was 97%, Availability dropped to 95% under the elevated ash-loading conditions due largely to sparger tube plugging problems precipitated by flyash agglomeration on the sparger tube Exhibit 5-16 Operation of CT-121 Scrubber walls during high ash loading when the ESP was deenergized. The high reliability demonstrated verified that a spare JBR is not required in a Low Ash_ Elevated Ash Cumulative commercial design offering. Phase Phase for Project Environmental Performance Total test period (hr) 11,750 7,250 19,000 Exhibit 5-17 shows SO. removal 2 Scrubber available (hr) 11,430 6,310 18,340 efficiency as a function of pressure Scrubber operating (hr) 8,600 5,210 13,810 drop across the JBR for five differ- Scrubber called upon (hr) 8,800 5,490 14,290 ent inlet concentrations. The greater i the pressure drop, the greater the Reliability a a 0.96 depth of slurry traversed by the flue leet El Availability’ 0.97 0.95 0.97 gas. As the SO, concentration in- Utilization’ 0.73 0.72 0.75 1 * Reliability = hours scrubber operated divided by the hours called upon to operate ’ Availability = hours scrubber available divided by the total hours in the period © Utilization = hours scrubber operated divided by the total hours in the period creased, removal efficiency de- creased, but adjustments in JBR fluid level could maintain the effi- ciency above 90% and, at lower SO, 5-38 Program Update 1999 Exhibit 5-17 SO, Removal Efficiency 100 et Inlet SO, 90 1000 ppm 2200 ppm 2500 ppm 3000 ppm | 3500 ppm 80 >eOden Above Yates 70 Design Basis All data at 75 MWe and pH 4.0 except 1000 ppm 6 8 10. 12 14 16 18 20 JBR Pressure Change (inches of water column) concentration levels, above 98%. Limestone utilization remained above 97% throughout the demonstration. Long-term particulate capture performance was tested with a partially deenergized ESP (approximately 90% efficiency), and is summarized in Exhibit 5-18. Analysis indicated that a large percentage of the outlet particulate matter is sulfate, likely a result of acid mist and gypsum carryover. This reduces the estimate of ash mass loading at the outlet to approximately 70% of the measured outlet particulates. For particulate sizes greater than 10 microns, capture efficiency was consistently greater than 99%. In the 1-10 micron range, capture efficiency was over 90%. Between 0.5 and | micron, the particulate removal dropped at times to negligible values possibly due to acid mist carryover entraining particulates in this size range. Below 0.5 micron, the capture efficiency increased to over 90%. Calculated air toxics removals across the CT-121 JBR, Environmental Control Devices Exhibit 5-18 - (ESP Marginally Operating) Particulate Capture Performance Commercial Applications Involvement of Southern Company (which owns Southern Company Services, Inc.), with more than 20,000 JBR Pressure Boiler Inlet Mass Outlet Mass Removal MWe of coal-fired generat- Change (inches of Load Loading Loading* Efficiency . nai water column) (MWe) (Ib/10° Btu) = (Ib/10° Btu) (%) ing capacity, is expected to enhance confidence in the 18 100 1.288 0.02 97.7 CT-121 process among other 10 100 1.392 0.010 99.3 large high-sulfur coal boiler 18 50 0.325 0.005 98.5 users. This process will be 10 50 0.303 0.006 98.0 applicable to 370,000-MWe *Federal NSPS is 0.03 Ib/10° Btu for units constructed after September 18, 1978. Plant Yates permit limit is 0.24 Ib/10° Btu as an existing unit. of new and existing generat- ing capacity by the year 2010. A 90% reduction in based on the measurements taken during the demon- stration, are shown in Exhibit 5-19. As to solids handling, the gypsum stacking method proved effective in the long term. Although chloride content was initially high in the stack due to the closed loop nature of the process (with concentrations often exceeding 35,000 ppm), a year later the chloride concen- tration in the gypsum dropped to less than 50 ppm, suit- able for wallboard and cement applications. The reduc- tion in chloride content was attributed to rainwater wash- ing the stack. Economic Performance Although the final economic analyses are not yet avail- able, it appears as though CT-121 technology offers sig- nificant economic advantages. FRP construction elimi- nates the need for prescrubbing and reheating flue gas. High system availability eliminates the need for a spare absorber module. Particulate removal capability pre- cludes the need for expensive (capital-intensive) ESP upgrades to meet increasingly tough environmental regulations. Environmental Control Devices SO, emissions from only the retrofit portion of this capacity represents more than 10,500,000 tons/yr of potential SO, control. Plant Yates continues to operate with the CT-121 scrubber as an integral part of the sites CAAA compli- ance strategy. Since the CCT Program demonstration, over 8,200 MWe equiva- lent of CT-121 FGD capacity has been sold to 16 customers in seven countries. The project received Power magazine’s 1994 Powerplant Award. Other Contacts David P. Burford, Project Manager, (205) 992-6329 Southern Company Services, Inc. P.O. Box 2625 Birmingham, AL 35202-2625 (205) 992-7535 (fax) Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, DOE/NETL, (412) 386-5991 References + A Study of Toxic Emissions from a Coal-Fired Power Plant Utilizing an ESP while Demonstrating the CCT CT-121 FGD Project. Final Report. Report No. DOE/PC/93253-T1. Radian Corporation. June 1994. (Available from NTIS as DE94016053.) * Comprehensive Report to Congress on the Clean Coal Technology Program: Demonstration of Innovative Applications of Technology for the CT-121 FGD Pro- cess. Southern Company Services, Inc. Report No. DOE/FE-0158. U.S. Department of Energy. February 1990. (Available from NTIS as DE9008110.) Exhibit 5-19 CT-121 Air Toxics Removal (JBR Components Only) awards include the Society of Plastics Industries’ 1995 Design Award for the mist eliminator, the Georgia Chapter of the Air 2 8 and Waste Management Association’s 1994 Outstanding Achievement Award, and the Georgia Chamber of Commerce’s 1993 Environmental Award. 3 Removal Efficiency (%) & v 8 Chloride Fluoride Arsenic Cadmium = Mercury ~— Selenium =~ Vanadium Program Update 1999 5-39 Environmental Control Devices NO, Control Technologies Environmental Control Devices Environmental Control Devices NO, Control Technology Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Project extended. Participant Southern Company Services, Inc. (SCS) Additional Team Members Electric Power Research Institute (EPRI)—cofunder Foster Wheeler Energy Corporation (Foster Wheeler)— technology supplier Georgia Power Company—host PowerGen—cofunder U.K. Department of Trade and Industry—cofunder EnTEC—technology supplier Radian—technology supplier Tennessee Technological University—technology supplier Southern Company—cofunder Location Coosa, Floyd County, GA (Georgia Power Company’s Plant Hammond, Unit No. 4) Technology Foster Wheeler’s low-NO, burner (LNB) with advanced overfire air (AOFA) and EPRI’s Generic NO, Control Intelligence System (GNOCIS) computer software. Plant Capacity/Production 500-MWe Coal Eastern bituminous coals, 1.7% sulfur Project Funding Total project cost $15,853,900 100% DOE 6,553,526 41 Participant 9,300,374 59 5-42 Program Update 1999 ASH BOILER ECONOMIZER COEERRERE ELECTROSTATIC PORTS PRECIPITATOR > PREHEATER| STACK COMBUSTION. AIR WINDBOX ———_, PULVERIZED PULVERIZED } COAL COAL ye LOW-NO, DRY WASTE TO DISPOSAL BURNERS LOW-NO,, BURNERS BOUNDARY AIR PORTS Project Objective To achieve 50% NO, reduction with the LNB/AOFA system; to determine the contributions of AOFA and LNB to NO, reduction and the parameters for optimal LNB/ AOFA performance; and to assess the long-term effects of LNB, AOFA, combined LNB/AOFA, and the GNOCIS advanced digital controls on NO, reduction, boiler perfor- mance, and peripheral equipment performance. Technology/Project Description AOFA involves (1) improving OFA mixing to lower over- all stoichiometry (less total excess air) while still avoiding high unburned combustible losses, (2) allowing deeper staging (sub-stoichiometric conditions in the flame zone, i.e., reducing atmosphere) without increasing combustible losses, and (3) introducing “boundary air” at the boiler walls to prevent corrosion caused by the reducing atmosphere. In the Foster Wheeler Controlled Flow/Split Flame (CFSF) LNB, fuel and air mixing (staged combustion) is controlled for localized, individual burner flames, rather than on a furnace-wide basis, by regulating the primary air/ fuel mixture, velocities, and turbulence to create a fuel-rich core with sufficient air to sustain combustion at a severely sub-stoichiometric air/fuel ratio. The burner also controls the rate at which additional air necessary to complete com- bustion is mixed with the flame solids and gases so as to maintain a deficiency of oxygen until the remaining com- bustibles fall below the peak NO, producing temperature (around 2,800 °F). The final excess air then can be allowed to mix with the unburned products so that combustion is completed at a relatively low temperature. The project has been reopened and extended to dem- onstrate an overall unit optimization system. Environmental Control Devices Calendar Year te ae +e 1988 1989 1990 1991 1992 1993 1994 1996 1998 1999 2001 3 4)/1 2 3 4 12 3 4 1 2 3 1 2 3 4 1 2 3 4 12 3 4 12 3 4 1 2 3 4 1 2 3 4 1 2 esign and Construction 6/90 9/88 12/89 Preaward A DOE selected project (CCT-II) 9/28/88 NEPA process completed (MTF) 5/22/89 Design completed 3/90 Cooperative agreement awarded 12/20/89 Results Summary Operational At full load, fly ash loss-on-ignition (LOI) was near 8% (compared to a baseline of 5%) for LNB alone and LNB/AOFA combined. AOFA accounted for an incremental NO, reduction beyond the use of LNB of approximately 17%, with additional reductions resulting from other operational changes. GNOCIS achieved a boiler efficiency gain of 0.5 per- centage points, a reduction in fly ash LOI levels of 1-3 percentage points, and a reduction in NO, emissions of 10-15% at full load. Environmental Control Devices Operation initiated, LNB 4/91 Construction completed, LNB 4/91 Construction started, LNB 3/91 Operation completed, AOFA 3/91 Environmental monitoring plan completed 9/14/90 Operation initiated, AOFA 6/90 Construction completed, AOFA 5/90 Construction started, AOFA 4/90 Operation system 6/94 Operation completed, LNB 1/92 Environmental Using LNB alone, long-term NO, emissions were 0.65 Ib/10° Btu, representing a 48% reduction from baseline conditions (1.24 Ib/10° Btu). Using AOFA only, long-term NO, emissions were 0.94 Ib/10° Btu, representing a 24% reduction from baseline conditions. Using LNB/AOFA, long-term NO, emissions were 0.40 1b/10° Btu, which represents a 68% reduction from baseline conditions. There was not a significant difference in emissions of trace metals, acid gases, and volatile organic com- pounds between AOFA and LNB operations. How- ever, there was a slight downward trend in emissions during LNB/AOFA operation. Final report | (Phase 1-3B) | issued 1/98 Final report (Phase 4) GNOCIS testing initiated 2/96 Operation initiated, LNB/AOFA with digital control Operation completed, LNB/AOFA 8/93 Operation initiated, LNB/AOFA 5/93 issued 9/98 Cooperative agreement resigned 9/15/99 Project completed/ final report issued 1/01* *Projected date “Years omitted Economic Capital cost for a 500-MWe wall-fired unit is $8.8/ kW for AOFA alone, $10.0/kW for LNB alone, $18.8/ kW for LNB/AOFA, and $0.5/kW for GNOCIS. Estimated cost of NO, removal is $86/ton using LNB/AOFA. Program Update 1999 5-43 Project Summary SCS conducted baseline characterization of the unit in an “as-found” condition from August 1989 to April 1990. The AOFA system was tested from August 1990 to March 1991. Following installation of the LNBs in the second quarter of 1991, the LNBs were tested from July 1991 to January 1992, excluding a three-month delay when the plant ran at reduced capacity. Post-LNB in- creases in fly ash LOI, along with increases in combus- tion air requirements and fly ash loading to the electro- static precipitator (ESP), adversely affected the unit’s stack particulate emissions. The LNB/AOFA testing was conducted from January 1992 to August 1993, excluding downtime for a scheduled outage and for portions of the test period due to excessive particulate emissions. How- ever, an ammonia flue gas conditioning system was added to improve ESP performance, which enabled the unit to operate at full load, and allowed testing to continue. Operational LOI increased significantly for the AOFA, LNB, and LNB/AOFA phases as seen in Exhibit 5-20, despite im- proved mill performance due to the replacement of the mills. Increased LOI was a concern not only because of Exhibit 5-20 LOI Performance Test Results the associated efficiency loss, but a potential Le . : Exhibit 5-21 loss of fly ash sales. The increased carbon in Ve ae the fly ash renders the material unsuitable for NO, vs. LOI Tests—All Sensitivities use in making concrete. : 0.60 During October 1992, SCS conducted 058 Arrow indicates direction of increasing parametric testing to determine the relation- ose v. operating parameter or burner adjustment ship between NO, and LOI emissions. The 2 054 ters test a . ill = +7 Increase Excess 07 . Extend Tip parameters tes ed were: excess oxygen, mi 5 9.527 Open Outer Reg. 7 . coal flow bias, burner sliding tip position, S, 0.50 burner outer register position, and burner F 048 . an Tip a "4 More Fuel to : ; sy : : ea ge | | cet eeee ill Bias pper Mills inner register position. Nitrogen oxide emis- 0.46 Inner Regi Inner Reg... . . 0.44 nner Register sions and LOI levels varied from 0.44— Excess O2 . 0.42 rin 0.57 Ib/10° Btu and 3—-10%, respectively. As 040 Outer Register expected, excess oxygen levels had consider- > 3g 5 6 7 8 9 0 UW LD able effect on both NO, and LOI. The results LOI (Percent) showed that there is some flexibility in select- ing the optimum operating point and making trade-offs between NO, emissions and fly ash LOI; however, much of the variation was the result of changes in excess oxy- gen. This can be more clearly seen in Exhibit 5-21 in which all sensitivities are plotted. This exhibit shows that, for excess oxygen, mill bias, inner register, and sliding tip, any adjustments to reduce NO, emissions are at the expense of increased fly ash LOI. In con- trast, the slope of the outer register characteristic suggests improvement in both NO, emissions and LOI can be achieved by adjustment of this damper. However, due to The need for more sophisticated 1&C equipment is illus- trated in Exhibit 5-22. There are trade-offs in boiler op- eration, e.g., aS excess air increases, NO, increases, LO] decreases, and boiler losses increase. The goal is to find and maintain an optimal operating condition. The 1&C systems tested included GNOCIS and carbon-in-ash analyzers. The GNOCIS software applies an optimizing proce- dure to identify the best set points for the plant, which are implemented automatically without operator intervention (closed-loop), or conveyed to the plant operators for implementation (open-loop). The major elements of the relatively small impact of the outer register adjust- ment on both NO, and LOI, Exhibit 5-22 Typical Trade-Offs in Boiler Optimization it is likely the positive NO./ LOI slope is an artifact of process noise. A subsidiary goal of the NOx project was to evaluate advanced instrumentation 14 12 AOFA L lo 12 So LNB = Baseline L +AOFA_ cane B gL ‘ome S 2 Sob BOL 2 LO = 0.8 Boe 3 AOFA g Zz Ff 7 oF 0.6 — — 47 isp F LNB r oat a 2|L Baseline ~ LNB+AOFA+Other F 02 0 100 200 300 400 500 600 100 200 300 400 500 600 Load, MW Load, MW 5-44 Program Update 1999 and controls (I&C) as ap- ‘Optimum Excess Air m \ Total Lol Flue Gas Boiler Losses Radiation plied to combustion control. ————<—_ Excess Air Environmental Control Devices Exhibit 5-23 Major Elements of GNOCIS Sensor Validation Instructions Plant > Advice / Control ) Historical Data Optimize GNOCIS GNOCIS are shown in Exhibit 5-23. The GNOCIS sys- tem has provided advice that reduced NO, emissions by 10-15% at full load, reduced fly ash LOI by 1-3 percent- age points, and improved boiler efficiency by 0.5 percent- age points. Environmental Long-term testing showed that the AOFA, LNBs, and LNB/AOFA provide full load NO, reductions of 24, 48, and 68%, respectively. The load-weighted average of NO, emission reductions were 14, 48, and 63%, respectively, for AOFA, LNB, LNB/AOFA. Although the long-term LNB/AOFA NO. level represents a 68% reduction from baseline levels, a substantial portion of the incremental change in NO, emissions between the LNB and the LNB/ AOFA configurations is the result of operational changes and is not the result of adding AOFA. A total of 63 days of valid long-term NO, emissions data were collected during the LNB/AOFA test phase. Based on this data set, the full-load, long-term NO, emis- sions were 0.40 Ib/10° Btu, which was consistent with earlier short-term test data. Earlier long-term testing had resulted in NO, emissions of 0.94 Ib/10° Btu for AOFA only and 0.65 Ib/10° Btu for and LNB only, respectively. Environmental Control Devices For reference, long-term baseline testing revealed an initial NO, emission rate of 1.4 1b/10° Btu. Air toxics testing was conducted for AOFA and LNB/AOFA operation. There was not a significant differ- ence in emissions of trace metals, acid gases, and volatile organic compounds for the two tests. There was a slight downward trend, however, in emissions during LNB/ AOFA operation. For elements associated with particu- late matter, ten show lower mean emissions during LNB/ AOFA operation (barium, beryllium, chromium, cobalt, copper, lead, manganese, nickel, phosphorus, and vana- dium); only two (arsenic and cadmium) show higher mean emissions during LNB/AOFA operation. Total particulate matter emissions also were lower during LNB/ AOFA operation; however, this was more an indication of ESP performance rather than burner configuration. Economic Estimated capital costs for a commercial 500-MWe wall- fired installation are: AOFA—$8.8/kW, LNB—$10.0/ kW, LNB/AOFA—$18.8/kW, and GNOCIS—$0.5/kW. Annual O&M costs and NO, reductions depend on the assumed load profile. Based on the actual load profile observed in the testing, the estimated annual O&M cost increase for LNB and AOFA is $333,351. Efficiency is decreased by 1.3 percent, and the NO, reduction is 68 percent of baseline, or 11,615 tons/year. The capital cost is $8,300,000 and the calculated cost of NO, removed is $86/ton. The addition of GNOCIS to the LNB/AOFA, using the actual load profile observed in the testing, results in a range of costs depending on whether the unit is operated to maximize NO, removal efficiency, or LOI. For the maximum NO, removal case, the efficiency is improved by 0.6 percent, the annual O&M cost is decreased by $228,058, the incremental NO, reduction is 11 percent (834 tons/year), and the capital cost is $250,000. The calculated cost per ton of NO, removed is -$299 (net gain due to increased efficiency). Project Extension On September 15, 1999, the cooperative agreement was extended and work has now begun on the design and installation of an overall unit optimization system. The work will be carried out as part of Phase 4 of the project. The overall goal of Phase 4 is to demonstrate on-line optimization techniques for power plant processes and for the unit as a whole. The major tasks include unit optimi- zation, boiler optimization, intelligent sootblowing, and precipitator modeling/optimization. Commercial Applications The technology is applicable to the 422 existing pre- NSPS wall-fired boilers in the United States, which burn a variety of coals. The GNOCIS technology is applicable to all fossil fuel-fired boilers, including units fired with natural gas and units cofiring coal and natural gas. The host has retained the technologies for commer- cial use. Foster Wheeler has equipped 86 boilers with low-NO, burner technology (51 domestic and 35 interna- tional)—1,800 burners for over 30,000 MWe capacity. Contacts John N. Sorge, (205) 257-7426 ICCT Project Manager Southern Company Services, Inc. P.O. Box 2625 Birmingham, AL 35202-2625 jnsorge@southernco.com Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James R. Longanbach, NETL, (304) 285-4659 jlonga@netl.doe.gov References * 500-MW Demonstration of Advanced Wall-Fired Combustion Techniques for the Reduction of Nitrogen Oxide (NO) Emissions from Coal-Fired Boilers— Phases 4—Digital Control System and Optimiza- tion. Southern Company Services, Inc. September 1998. Program Update 1999 5-45 Environmental Control Devices NO, Control Technology Demonstration of Coal Reburning for Cyclone Boiler NO, Control Project completed. Participant The Babcock & Wilcox Company Additional Team Members Wisconsin Power and Light Company—cofunder and host Sargent and Lundy—engineer for coal handling Electric Power Research Institute—cofunder State of Illinois, Department of Energy and Natural Resources—cofunder Utility companies (14 cyclone boiler operators)— cofunders Location Cassville, Grant County, WI (Wisconsin Power and Light Company’s Nelson Dewey Station, Unit No. 2) Technology The Babcock & Wilcox Company’s coal-reburning system, Coal Reburn Plant Capacity/Production 100-MWe Coal Illinois Basin bituminous (Lamar), 1.15% sulfur, 1.24% nitrogen Powder River Basin (PRB) subbituminous, 0.27% sulfur, 0.55% nitrogen Project Funding Total project cost $13,646,609 100% DOE 6,340,788 46 Participant 7,305,821 54 5-46 Program Update 1999 BOILER BURNOUT ZONE OVERFIRE AIR ELECTROSTATIC. PRECIPITATOR COAL REBURN BURNERS ar PULVERIZED =? COAL — 2 AIR MAIN ——| COMBUSTION ZONE CYCLONE BURNER SLAG TO DISPOSAL 7 AIR 2 AIR PREHEATER | PRIMARY DRY WASTE TO DISPOSAL Project Objective To demonstrate the technical and economic feasibility of achieving greater than 50% reduction in NO, emissions with no serious impact on cyclone combustor operation, boiler performance, or other emission streams. Technology/Project Description Babcock & Wilcox Coal Reburn reduces NO, in the fur- nace through the use of multiple combustion zones. The main combustion zone uses 70-80% of the total heat- equivalent fuel input to the boiler and slightly less than normal combustion air input. The balance of the coal (20-30%), along with significantly less than the theoreti- cally determined requirement of air, is fed to the reburning zone above the cyclones to create an oxygen-deficient condition. The NO, formed in the cyclone burners reacts with the resultant reducing flue gas and is converted into nitrogen in this zone. Completion of the combustion process occurs in the third zone, called the burnout zone, where the balance of the combustion air is introduced. Coal Reburn can be applied with the cyclone burners operating within their normal, noncorrosive, oxidizing conditions, thereby minimizing any adverse effects of reburn on the cyclone combustor and boiler performance. This project involved retrofitting an existing 100-MWe cyclone boiler that is representative of a large population of cyclone units. Environmental Control Devices Calendar Year 1988 1998 4/90 Design and Construction DOE selected project (CCT-Il) 9/28/88 Operation initiated 12/91 Construction completed 11/91 3/94 Operation A Project completed/final report issued 3/94 Operation completed 12/92 Preoperational tests initiated 11/91 Environmental monitoring plan completed 11/18/91 Cooperative agreement awarded 4/2/90 Design completed 6/91 NEPA process completed (EA) 2/12/91 Ground breaking/construction started 11/90 Results Summary Environmental * Coal Reburn achieved greater than 50% NO, reduc- tion at full load with Lamar bituminous and PRB subbituminous coals. + Reburn-zone stoichiometry had the greatest effect on NO, control. * Gas recirculation was vital to maintaining reburn- zone stoichiometry while providing necessary burner cooling, flame penetration, and mixing. * Opacity levels and electrostatic precipitator (ESP) performance were not affected by Coal Reburn with either coal tested. * Optimal Coal Reburn heat input was 29-30% at full load and 33-35% at half to moderate loads. Environmental Control Devices Operational No major boiler performance problems were experi- enced with Coal Reburn operations. Boiler turndown capability was 66%, exceeding the 50% goal. ESP efficiency improved slightly during Lamar coal testing and did not change with PRB coal. Coal fineness levels above the nominal 90% through 200 mesh were maintained, reducing unburned carbon losses (UBCL). UBCL was the only major contributor to boiler effi- ciency loss, which was 0.1, 0.25, and 1.5% at loads of 110-, 82-, and 60-MWe, respectively, when using Lamar coal. With PRB coal, the efficiency loss ranged from zero at full load to 0.3% at 60-MWe. Superior flame stability was realized with PRB coal, contributing to better NO, control than with Lamar coal. + Expanded volumetric fuel delivery with reburn burn- ers enabled switching to PRB low-rank coal without boiler derating. Economic * Capital costs for 110- and 605-MWe plants were $66/kW and $43/kW, respectively. + Levelized 10- and 30-year busbar power costs for a 110-MWe plant were 2.4 and 2.3 mills/kWh, respec- tively. + Levelized 10- and 30-year busbar power costs for a 605-MWe plant were 1.6 and 1.5 mills/kWh, respec- tively. (Costs are in 1990 constant dollars.) Program Update 1999 5-47 Project Summary Although cyclone boilers represent only 15% of the pre- NSPS coal-fired generating capacity, they contribute 21% of the NO, formed by pre-NSPS coal-fired units. This is due to the cyclone combustor’s inherent turbulent, high- temperature combustion process. Consequently, cyclone boilers are targeted for NO, reduction under the CAAA and state implementation plans. However, at the time of this demonstration, there was no cost-effective combus- tion modification available for cyclone boiler NO, control. Babcock & Wilcox Coal Reburn offers an economic and operationally sound response to the environmental impetus. This technology avoids cyclone combustor modification and associated performance complications and provides an alternative to postcombustion NO, con- trol options, such as SCR, having relatively higher capital and/or operating costs. The majority of the testing was performed firing Illinois Basin bituminous coal (Lamar), as it is typical of the coal used by many utilities operating cyclones. Subbi- tuminous PRB coal tests were performed to evaluate the effect of coal switching on reburn operation. Wisconsin Power and Light’s strategy to meet Wisconsin’s sulfur emission limitations as of January 1, 1993, was to fire low-sulfur coal. Environmental Performance Three sequences of testing of Coal Reburn used Lamar coal. Parametric optimization testing was used to set up the automatic controls. Performance testing was run with the unit in full automatic control at set load points. Long- term testing was performed with reburn in operation while the unit followed system load demand require- ments. PRB coal was tested by parametric optimization and performance modes. Exhibit 5-24 shows changes in NO, emissions and boiler efficiency using the reburn system for various load conditions and coal types. Coal Reburn tests on both the Lamar and PRB coals indicated that vari the most critical factor in changing NO, emissions levels. The reburn-zone stoichiometry can be varied by alternat- ion of reburn-zone stoichiometry was ing the air flow quantities (oxygen availability) to the reburn burners, the percent reburn heat input, the gas recirculation flow rate, or the cyclone stoichiometry. Hazardous air pollutant (HAP) testing was performed using Lamar test coal. HAP emissions Exhibit 5-24 Coal Reburn Test Results were generally well within expected levels, and emissions with Coal Reburn were comparable to baseline operation. No major effect of reburn on trace- Boiler Load metals partitioning was discernible. 110-MWe 82-MWe 60-MWe None of the 16 targeted polynuclear aromatic semi-volatile organics (con- Lamar coal trolled under Title III of CAAA) was /10° /9, cti NO, (Ib/10° Btu/% reduction) 0.39/52 0.36/50 0.44/36 present in detectable concentrations, at Boiler efficiency losses due to 0.1 0.25 1.5 a detection limit of 1.2 parts per billion. unburned carbon (%) Powder River Basin coal Operational Performance: NO, (Ib/10° Btu/% reduction) 0.34/55 0.31/52 0.30/53 For Lamar coal, the full-, medium-, and . ae: low-load efficiency losses, due to un- Boiler efficiency losses due 0.0 0.2 0.3 to unburned carbon (%) burned carbon, were higher than the baseline by 0.1, 0.25, and 1.5% respec- 5-48 Program Update 1999 A = Wisconsin Power and Light Company’s Nelson Dewey Station hosted the successful demonstration of Coal Reburn. tively. Full-, medium-, and low-load efficiency losses with PRB coal were 0.0, 0.2, and 0.3%, respectively. Coal Reburn burner flame stability improved with PRB coal. During Coal Reburn operation with Lamar coal, the operators continually monitored boiler internals for in- creased ash deposition and the on-line performance moni- toring system for heat transfer changes. At no time throughout the system optimization or long-term opera- tion period were any slagging or fouling problems ob- served. In fact, during scheduled outages, internal boiler inspections revealed that boiler cleanliness had actually improved. Extensive ultrasonic thickness measurements were taken of the furnace wall tubes. No observable decrease in wall tube thickness was measured. Another significant finding was that Coal Reburn minimizes and possibly eliminated a 0Q-25% derating normally associated with switching to subbituminous coal in a cyclone unit. This derating results from using a lower Btu fuel in a cyclone combustor, which has a limited coal feed capacity. The Coal Reburn system transferred about 30% of the coal feed out of the cyclone to the reburn burn- ers, bringing the cyclone feed rate down to a manageable level, while maintaining full-load heat input to the unit. Environmental Control Devices Economic Performance An economic analysis of total capital and levelized rev- enue requirements was conducted using the “Electric Power Research Institute Economic Premises” for retrofit of 110- and 605-MWe plants. In addition, annualized costs per ton of NO, removed were developed for 110- and 605-MWe plants over both 10 and 30 years. The results of these analyses are shown in Exhibit 5-25. These values assumed typical retrofit conditions and did not take into account any fuel savings from use of low- rank coal. The pulverizers and associated coal handling VY The coal pulverizer is part of Babcock & Wilcox Coal Reburn. This system has been retained by Wisconsin Power and Light for NO, emission control at the Nelson Dewey Station. Environmental Control Devices were taken into account. Site-specific parameters that can significantly impact these retrofit costs included the state of the existing control system, availability of flue gas recirculation, space for coal pulverizers, space for reburn burners and overfire air ports within the boiler, scope of coal-handling modification, sootblow- ing capacity, ESP capacity, steam temperature control capacity, and boiler circulation considerations. Commercial Applications Coal Reburn is a retrofit technology applicable to a wide range of utility and industrial cyclone boilers. The current U.S. Coal Reburn market is estimated to be approxi- mately 26,000 MWe and consists of about 120 units ranging from 100- to 1,150-MWe with most in the 100- to 300-MWe range. The project technology has been retained by Wiscon- sin Power and Light for commercial use. Contacts Dot K. Johnson, (330) 829-7395 McDermott Technologies, Inc. 1562 Beeson Street Alliance, OH 44601 (330) 821-7801 (fax) dot.k.johnson@medermott.com Lawrence Saroff, DOE/HQ, (301) 903-9483 John C. McDowell, NETL, (412) 386-6175 Exhibit 5-25 Coal Reburn Economics (1990 Constant Dollars) Plant Size Costs 110-MWe 605-MWe Total capital cost ($/kW) 66 43 Levelized busbar power cost (mills/kWh) 10-year life 2.4 1.6 30-year life 2.3 1.5 Annualized cost ($/ton of NO. removed) 10-year life 1,075 408 30-year life 692 263 References * Demonstration of Coal Reburning for Cyclone Boiler NO, Control: Final Project Report. Report No. DOE/PC/89659-T16. The Babcock & Wilcox Company. February 1994. (Available from NTIS as DE94013052, Appendix 1 as DE94013053, Appendix 2 as DE94013054.) * Public Design Report: Coal Reburning for Cyclone Boiler NO, Control. The Babcock & Wilcox Com- pany. August 1991. (Available from NTIS as DE92012554.) * Comprehensive Report to Congress on the Clean Coal Program: Demonstration of Coal Reburning for Cyclone Boiler NO, Control. Report No. DOE/ FE-0157. U.S. Department of Energy. February 1990. (Available from NTIS as DE90008111.) Program Update 1999 5-49 Environmental Control Devices NO, Control Technology Full-Scale Demonstration of Low-NO, Cell Burner Retrofit Project completed. Participant The Babcock & Wilcox Company Additional Team Members The Dayton Power and Light Company—cofunder and host Electric Power Research Institute—cofunder Ohio Coal Development Office—cofunder Tennessee Valley Authority—cofunder New England Power Company—cofunder Duke Power Company—cofunder Allegheny Power System—cofunder Centerior Energy Corporation—cofunder Location Aberdeen, Adams County, OH (Dayton Power and Light Company’s J.M. Stuart Plant, Unit No. 4) Technology The Babcock & Wilcox Company’s low-NO, cell burner (LNCB*) system Plant Capacity/Production 605-MWe Coal Bituminous, medium sulfur Project Funding Total project cost $11,233,392 100% DOE 5,442,800 48 Participant 5,790,592 52 LNCB is a registered trademark of The Babcock & Wilcox Company. 5-50 Program Update 1999 BOILER WINDBOX BOTTOM ASH ELECTROSTATIC PRECIPITATOR SECONDARY AIR PORT LOW-NOx CELL BURNER SECONDARY ee SYSTEM AIR PORT @ ROWS SHOWN) Z c \ FLY ASH TO DISPOSAL c COAL a AND AIR AIR LOW-NO, CELL BURNER SYSTEM (2 ROWS SHOWN) Project Objective To demonstrate, through the first commercial-scale full burner retrofit, the cost-effective reduction of NO, from a large baseload coal-fired utility boiler with LNCB® tech- nology; to achieve at least a 50% NO, reduction without degradation of boiler performance at less cost than that of conventional low-NO, burners. Technology/Project Description The LNCB* technology replaces the upper coal nozzle of the standard two-nozzle cell burner with a secondary air port. The lower burner coal nozzle is enlarged to the same fuel input capacity as the two standard coal nozzles. The LNCB* operates on the principle of staged combustion to reduce NO, emissions. Approximately 70% of the total air (primary, secondary, and excess air) is supplied through or around the coal-feed nozzle. The remainder of the air is directed to the upper port of each cell to com- plete the combustion process. The fuel-bound nitrogen compounds are converted to nitrogen gas, and the reduced flame temperature minimizes the formation of thermal NO,. The demonstration was conducted on a Babcock & Wilcox-designed, supercritical, once-through boiler equipped with an electrostatic precipitator (ESP). This unit, which is typical of cell burner boilers, contained 24 two-nozzle cell burners arranged in an opposed-firing configuration. Twelve burners (arranged in two rows of six burners each) were mounted on each of two opposing walls of the boiler. All 24 standard cell burners were removed and 24 new LNCBs® were installed. Alternate LNCB*® on the bottom rows were inverted, with the air port then being on the bottom to ensure complete combus- tion in the lower furnace. Environmental Control Devices Calendar Year 1988 3 4/1 2 3 4/1 2 3 4/)/1 2 3 1998 12/89 Preaward DOE selected project (CCT-IIl) 12/19/89 NEPA process completed (MTF) 8/10/90 Cooperative agreement awarded 10/11/90 Design completed 10/90 10/90 Designand 12/91 Construction Operation Operation Operation completed 4/93 initiated 12/91 Construction completed 11/91 Preoperational tests initiated 11/91 Ground breaking/construction started 9/91 Environmental monitoring plan completed 8/9/91 Results Summary Environmental + Short-term optimization testing (all mills in service) showed NO, reductions in the range of 53.0-55.5%, 52.5-54.7%, and 46.9-47.9% at loads of 605-MWe, 460-MWe, and 350-MWe, respectively. * Long-term testing at full load (all mills in service) showed an average NO, reduction of 58% (over 8 months). + Long-term testing at full load (one mill out of service) showed an average NO, reduction of 60% (over 8 months). * CO emissions averaged 28-55 ppm at full load with LNCB* in service. + Fly ash increased, but ESP performance remained virtually unchanged. Environmental Control Devices Project completed/final report issued 12/95 Operational Unit efficiency remained essentially unchanged. Unburned carbon losses (UBCL) increased by ap- proximately 28% for all tests, but boiler efficiency loss was offset by a decrease in dry gas loss due to a lower boiler economizer outlet gas temperature. Boiler corrosion with LNCB® was roughly equivalent to boiler corrosion rates prior to retrofit. Economic Capital cost for a 600-MWe plant was $9/kW (19948). Levelized cost for a 600-MWe plant was estimated at 0.284 mills/kWh and $96.48/ton of NO, removed. Program Update 1999 5-51 Project Summary Utility boilers equipped with cell burners currently com- prise 13% or approximately 23,000-MWe of pre-NSPS. coal-fired generating capacity. Cell burners are designed for rapid mixing of the fuel and air. The tight burner spacing and rapid mixing minimize the flame size while maximizing the heat release rate and unit efficiency. Combustion efficiency is good, but the rapid heat release produces relatively large quantities of NO,. To reduce NO, emissions, the LNCB" has been de- signed to stage mixing of the fuel and combustion air. A key design criterion was accomplishing delayed fuel-air mixing with no modifications to waterwall panels. A plug-in design reduces material costs and outage time required to complete the retrofit, compared to installing conventional, internally staged low-NO, burners. LNCB" provides a lower cost alternative to address NO, reduction requirements for cell burners. Environmental Performance The initial LNCB* configuration resulted in excessive CO and H,S emissions. Through modeling, a revised configu- ration was developed to address the problem without compromising boiler performance. The modification was incorporated and validated model capabilities. Following parametric testing to establish optimal operating modes, a series of optimization tests were con- ducted on the LNCB* to assess environmental and opera- tional performance. Two sets of measurements were taken, one by Babcock & Wilcox and the other by an independent company, to validate data accuracy. Conse- quently, the data provided is a range reflecting the two measurements. The average NO, emissions reduction achieved at full load with all mills in service ranged from 53.0-55.5%. With one mill out of service at full load, the average NO, reduction ranged from 53.3-54.5%. Average NO, reduc- tion at intermediate load (about 460-MWe) ranged from 52.5-54.7%. At low loads (about 350-MWe), average 5-52 Program Update 1999 NO, reduction ranged from 46.9-47.9%. NO, emissions were monitored over the long-term at full load for all mills in service and one mill out of service. Each test spanned an 8-month period. NO, emission reductions realized were 58% for all mills in service and about 60% for one mill out of service. Complications arose in assessing CO emissions relative to baseline because baseline calibration was not sufficiently refined. However, accurate measurements were made with LNCB® in service. Carbon monoxide emissions were corrected for 3.0% O, and measured at full, intermediate, and low loads. The range of CO emis- sions at full load with all mills in service was 28-55 ppm and 20-38 ppm with one mill out of service. At interme- diate loads (about 460-MWe), CO emissions were 28-45 ppm and at low loads (about 350-MWe), 5-27 ppm. Particulate emissions were minimally impacted. The LNCB* had little effect on flyash resistivity, largely due to SO, injection, and therefore ESP removal efficiency re- mained very high. Baseline ESP collection efficiencies for full load with all mills in service, full load with one mill in service, and intermediate load with one mill out of service were 99.50, 99.49, and 99.81%, respectively. For the same conditions, in the same sequence with LNCB* in operation, ESP collection efficiencies were 99.43, 99.12, and 99.35%, respectively. Operational Performance Furnace exit gas temperature, or secondary superheater inlet temperature, initially decreased by 100 °F but even- tually rose to within 10 °F of baseline conditions. The UBCL increased by approximately 28% for all tests. The most significant increase from baseline data occurred for a test with one mill out of service. A 52% increase in UBCL resulted in an efficiency loss of 0.69%. Boiler efficiency showed very little change from baseline. The average for all mills in service increased by 0.16%. The higher post-retrofit efficiency was attributed to a decrease in dry gas loss with lower economizer gas ‘Secondary-air port replaces top nozzie of ‘standard cell burner, Coal pipe modification so that coal supply is to bottom nozzle only, Larger capacity burner nozzle replaces bottom nozzle of standard cell burner Pulverized Coal and Primary Air A Single LNCB® Retrofit. outlet temperature (and subsequent lower air heater gas outlet temperature), offsetting UBCL, and CO emis- sion losses. UBCL. Because sulfidation is the primary corrosion mecha- Also, increased coal fineness mitigated nism in substoichiometric combustion of sulfur-contain- ing coal, H,S levels were monitored in the boiler. After optimizing LNCB” operation, levels were largely at the lower detection limit. There were some higher local readings, but corrosion panel tests established that corro- sion rates with LNCB® were roughly equivalent to pre- retrofit rates. Ash sample analyses indicated that ash deposition would not be a problem. The LNCB® ash differed little from baseline ash. Furthermore, the small variations observed in furnace exit gas temperature between baseline Environmental Control Devices VY = The LNCB* is viewed from within the boiler. and LNCB® indicated little change in furnace slagging. Startup and turndown of the unit were unaffected by conversion to LNCB*. Economic Performance The economic analyses were performed for a 600-MWe nominal unit size and typical location in the midwest United States. A medium-sulfur, medium-volatile bitumi- nous coal was chosen as the typical fuel. For a baseline NO, emission level of 1.2 1b/10° Btu and a 50% reduction target, the estimated capital cost was $9/kW (19948). Environmental Control Devices The levelized cost of electricity was estimated at 0.284 mills/kWh or $96.48/ton of NO, removed. Commercial Applications The low cost and short outage time for retrofit make the LNCB" design the most cost-effective NO, control technology available today for cell burner boilers. The LNCB* system can be installed at about half the cost and time of other commercial low-NO, burners. Dayton Power & Light has retained the LNCB” for use in commercial service. Seven commercial contracts have been awarded for 172 burners, valued at $24 mil- lion. LNCB* have already been installed on more than 4,600 MWe of capacity. The demonstration project received R&D magazine’s 1994 R&D Award. Contacts Dot K. Johnson, (330) 829-7395 McDermott Technologies, Inc. 1562 Beeson Street Alliance, OH 44601 (330) 821-7801 (fax) dot.k.johnson@mcedermott.com Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, NETL, (412) 386-5991 References * Final Report: Full-Scale Demonstration of Low- NO, Cell Burner Retrofit. Report No. DOE/PC/ 90545-T2. The Babcock & Wilcox Company. De- cember 1995. (Available from NTIS as DE96003766.) * Public Design Report: Full-Scale Demonstration of Low-NO, Cell Burner Retrofit. Report No. DOE/ PC/90545-T4. The Babcock & Wilcox Company. August 1991. (Available from NTIS as DE92009768.) * Comprehensive Report to Congress on the Clean Coal Technology Program: Full-Scale Demonstra- tion of Low-NO, Cell-Burner Retrofit. The Babcock & Wilcox Company. Report No. DOE/FE-0197P. U.S. Department of Energy. July 1990. (Available from NTIS as DE90018026.) A The connections to the LNCB" are viewed from outside the boiler. Program Update 1999 5-53 Environmental Control Devices NO, Control Technology Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler Project completed. Participant Energy and Environmental Research Corporation Additional Team Members Public Service Company of Colorado—cofunder and host Gas Research Institute—cofunder Colorado Interstate Gas Company—cofunder Electric Power Research Institute—cofunder Foster Wheeler Energy Corp.—technology supplier Location Denver, Adams County, CO (Public Service Company of Colorado’s Cherokee Station, Unit No. 3) Technology Energy and Environmental Research Corporation’s gas- reburning (GR) system and Foster Wheeler Energy Corp.’s Low-NO, burners (LNB) Plant Capacity/Production 172-MWe (gross), 158-MWe (net) Coal Colorado bituminous, 0.40% sulfur, 10% ash Project Funding Total project cost $17,807,258 100% DOE 8,895,790 50 Participant 8,911,468 50 Project Objective To attain up to a 70% decrease in the emissions of NO, from an existing wall-fired utility boiler firing low-sulfur coal using both gas reburning and low-NO, burners (GR-LNB) and to assess the impact of GR-LNB on boiler performance. 5-54 Program Update 1999 BOILER OVERFIRE AIR —> | | NATURAL GAS —— | | RECIRCULATED | FLUE GAS LOW-NO, hice BURNERS ASH ECONOMIZER __-— REBURN ZONE BURNOUT ZONE BAGHOUSE > AIR PREHEATER STACK | 7 pee TO DISPOSAL — PRIMARY COMBUSTION ZONE Technology/Project Description Gas reburning involves firing natural gas (up to 25% of total heat input) above the main coal combustion zone in a boiler. This upper-level firing creates a slightly fuel-rich zone. NO, drifting upward from the lower region of the furnace is stripped of oxygen as the reburn fuel is com- busted in this zone and converted to molecular nitrogen. Low-NO, burners positioned in the coal combustion zone retard the production of NO, by staging the burning pro- cess so that the coal-air mixture can be carefully con- trolled at each stage. The synergistic effect of adding a reburning stage to wall-fired boilers equipped with low- NO, burners was intended to lower NO, emissions by up to 70%. Gas reburning was demonstrated with and with- out the use of recirculated flue gas. A series of parametric tests were performed on the gas reburning system, varying operational control param- eters, and assessing the effect on boiler emissions, com- pleteness of combustion (carbon-in-ash or loss-on-igni- tion), thermal efficiency, and heat rate. A one-year, long- term testing program was performed in order to judge the consistency of system outputs, assess the impact of long- term operation on the boiler equipment, gain experience in operating GR-LNB in a normal load-following environ- ment, and develop a database for use in subsequent GR- LNB applications. Both first- and second-generation gas- reburning tests were performed. Environmental Control Devices Calendar Year ae 1988 1989 1990 1991 1992 1993 1994 1995 1996 1998 1999 3 4/1 2 3 4 12 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 12 3 4 1 2 12/89 10/90 11/92 10/98 Preaward Design and Construction Operation ts ‘ Restoration completed 11/95 Operation completed 1/95 | Operation initiated 11/92 Construction completed 11/92 Project completed/final report issued 10/98 ‘—Long-term operations started 4/93 Design completed 8/91 Ground breaking/construction started 6/91 Cooperative agreement awarded 10/13/90 NEPA process completed (MTF) 9/6/90 Environmental monitoring plan completed 7/26/90 DOE selected project (CCT-III) 12/19/89 “Years omitted Results Summary Environmental + LNB alone reduced NO, emissions from a pre-con- struction baseline of 0.73 1b/10° Btu to 0.46 Ib/10° Btu (at 3.5% O,), a 37% NO, reduction. + First-generation GR, which incorporated flue gas recirculation, in combination with LNB, reduced NO, emissions to an average 0.25 Ib/10° Btu (at 3.25% O,), a 66% NO, reduction at an 18% gas heat input rate. * Second-generation GR, without flue gas recirculation, in combination with LNB reduced NO, emissions to an average 0.26 Ib/10° Btu, a 64% NO, reduction with only 12.5% gas heat input. * Both first- and second-generation GR with LNB were capable of reducing NO, emissions by up to 70% for short periods of time, the average was approxi- mately 65%. Environmental Control Devices * After modifying the overfire air system to enhance penetration and turbulence (as part of second-genera- tion GR), CO emissions were controlled to acceptable levels at low gas heat input rates. SO, emissions and particulate loadings were reduced by the percentage heat input supplied by GR. Operational * Boiler efficiency decreased < 1.0%. * There was no measurable boiler tube wear and only a small amount of slagging. * Carbon-in-ash and CO levels were acceptable for first- and second-generation GR with LNB, but not with LNB alone. Ec onomic Capital cost for a GR-LNB retrofit of a 300-MWe plant is $26.01/kW (19968) plus the gas pipeline cost, if not in place ($12.14/kW for GR only and $13.87/kW for LNB only). Operating costs were related to the gas/coal cost differ- ential and the value of SO, emission allowances be- cause GR reduces SO, emissions when displacing coal. Program Update 1999 5-55 Project Summary The demonstration established that GR-LNB offers a cost- effective option for deep NO, reduction on wall-fired boilers. GR-LNB NO, control performance approached that of selective catalytic reduction (SCR) but at signifi- cantly lower cost. The importance of cost-effective tech- nology for deep NO, reduction is the need for NO, reduc- tion in ozone nonattainment areas beyond what is cur- rently projected in Title IV of the CAAA. Title I of the CAAA deals with ozone nonattainment and is currently the driving force for deep NO, reduction in many regions of the country. The GR-LNB was installed and evaluated on a 172- MWe (gross) wall-fired boiler—a Babcock & Wilcox balanced-draft pulverized coal-fired unit. The GR system, A A worker inspects the support ring for the Foster Wheeler low-NO, burner installed in the boiler wall. 5-56 Program Update 1999 including an overfire air system, was designed and installed by Energy and Environmental Research Cor- poration. The LNBs were designed and installed by Foster Wheeler Energy Corp. Parametric testing began in October 1992 and was completed in April 1993. The parametric tests examined the effect of process variables (such as zone stoichiometric ratio, percent gas heat input, percent overfire air, and load) on NO, reduction, SO, reduction, CO emissions, carbon-in-ash, and heat rates. The baseline performance of the LNB was also established. Environmental Performance At a constant load (150-MWe) and a constant oxygen level at the boiler exit, NO, emissions were reduced with increasing gas heat input. At gas heat inputs greater than 10%, NO, emissions were reduced marginally as gas heat input increased. Natural gas also reduced SO, emissions in proportion to the gas heat input. At the Cherokee Station, low-sulfur (0.40%) coal is used, and typical SO, emissions are 0.65 Ib/10° Btu. With a gas heat input of 20%, SO, emissions decreased by 20% to 0.52 Ib/10° Btu. The CO, emissions were also reduced as a result of using natural gas because it has a lower carbon-to-hydrogen ratio than coal. At a gas heat input of 20%, the CO, emissions were reduced by 8%. Long-term testing was initiated in April 1993 and completed in January 1995. The objectives of the test were to obtain operating data over an extended period when the unit was under routine commercial service, determine the effect of GR-LNB operation on the unit, and obtain incremental maintenance and operating costs with GR. During long-term testing, it was determined that flue gas recirculation had minimal effect on NO, emissions. A second series of tests were added to the demon- stration to evaluate a modified or second-generation sys- tem. Modifications are summarized as follows: + The flue gas recirculation system, originally de- signed to provide momentum to the natural gas, was removed. (This change significantly reduced capital costs.) + Natural gas injection was optimized at 10% gas heat input compared to the initial design value of 18%. The removal of the flue gas recirculation system required installation of high-velocity injectors, which made greater use of available natural gas (This modification reduced natural gas usage and thus operating costs.) pressure. * Overfire air ports were modified to provide higher jet momentum, especially at low total flows. Over 4,000 hours of operation were achieved, with the results as shown in Exhibit 5-26. Although the 37% NO, reduction performance of LNB was less than the expected 45%, the overall objectives of the demonstra- tion were met. Boiler efficiency decreased by only 1% during gas reburning due to increased moisture in the fuel resulting from natural gas use. Further, there was no measurable tube wear, and only small amounts of slagging occurred during the GR-LNB demonstration. However, with LNB alone, carbon-in-ash and CO could not be maintained at acceptable levels. Exhibit 5-26 NO, Data from Cherokee Station, Unit No. 3 GR Generation First Second Baseline (Ib/10° Btu) 0.73 0.73 Avg NO, reduction (%) LNB 37 44 GR-LNB 66 64 Avg gas heat input (%) 18 12.5 Environmental Control Devices Economic Performance GR-LNB is a retrofit technology in which the economic benefits are dependent on the following site-specific fac- tors: * Gas availability at the site, * Gas/coal cost differential, * Boilerefficiency, * SO, removal requirements, and + Value of SO, emission credits. Based on the demonstration, GR-LNB is expected to achieve at least a 64% NO, reduction with a gas heat input of 12.5%. The capital cost estimate for a 300-MWe wall-fired installation is $26.01/kW (1996 $) plus gas pipeline costs, if required. This cost includes both equip- ment and installation costs and a 15% contingency. The GR and LNB system capital costs can be easily separated from one another because they are independent systems. The capital cost for the GR system only is estimated at $12.14/kW. The LNB system capital cost is $13.87/kW. Operating costs are almost entirely related to the differential cost of natural gas and coal and reduced by the value of the SO, emission credits received due to absence of sulfur in the gas. A fuel differential of $1.00/10° Btu was used because gas costs more than coal on a heating value basis. Boiler efficiency was estimated to decline by 0.80%; the cost of this decline was calculated using a composite fuel cost of $1.67/10° Btu. Overfire air booster and cooling fan auxiliary loads will be partially offset by lower loads on the pulverizers. No additional operating labor is required, but there is an increase in maintenance costs. Allowances also were made for overhead, taxes, and insurance. Based on these assumptions and assum- ing an SO, credit allowance of $95/ton (Feb. 1996$), the net operating cost is $2.14 million per year and the NO, removal cost is $786/ton (constant 1996$). Environmental Control Devices Commercial Applications Current estimates indicate that about 35 existing wall- ° fired utility installations, plus industrial boilers, could make immediate use of this technology. The technology can be used in retrofit, repowering, or greenfield installa- tions. There is no known limit to the size or scope of the application of this technology combination. GR-LNB is expected to be less capital intensive, or less costly, than selective catalytic reduction. GR-LNB functions equally well with any kind of coal. Public Service Company of Colorado, the host utility, decided to retain the low-NO, burners and the gas- reburning system for immediate use; however, a restoration was required to remove the flue gas recircula- tion system. Energy and Environmental Research Corporation has been awarded two contracts to provide gas-reburn- ing systems for five cyclone coal-fired boilers: TVA’s Allen Unit No. 1, with options for Unit Nos. 2 and 3 (identical 330-MWe Units); and Baltimore Gas & Electric’s C.P. Crane, Unit No. 2, with an option for Unit No. | (similar 200-MWe Units). Use of the technology One of the first installations of the technology took place at the also extends to overseas markets. Ladyzkin State Power Station in Ladyzkin, Ukraine. This demonstration project was one of two that re- ceived the Air and Waste Management Association’s 1997 J. Deanne Sensenbaugh Award. Contacts Blair A. Folsom, Sr. V.P., (949) 859-8851, ext. 140 General Electric Energy and Environmental Research Corporation 18 Mason Irvine CA 92618 (949) 859-3194 (fax) Lawrence Saroff, DOE/HQ, (301) 903-9483 Jerry L. Hebb, NETL, (412) 386-6079 References Evaluation of Gas Reburning and Low-NO, Burn- ers on a Wall-Fired Boiler: Performance and Eco- nomics Report, Gas Reburning—Low-NO, Burner System, Cherokee Station Unit No. 3, Public Ser- vice Company of Colorado. Final Report. July 1998. Guideline Manual: Gas Reburning—Low-NO, Burner System, Cherokee Station Unit No. 3, Public Service Company of Colorado. Final Report. July 1998. Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler (Long-Term Testing, April 1993—January 1995). Report No. DOE/PC/90547- T20. Energy and Environmental Research Corpora- tion. June 1995. (Available from NTIS as DE95017755.) Evaluation of Gas Reburning and Low-NO, Burn- ers on a Wall-Fired Boiler (Optimization Testing, November 1992—April 1993). Report No. DOE/PC/ 90547-T19. Energy and Environmental Research Corporation. June 1995, (Available from NTIS as DE95017754.) Program Update 1999 5-57 Environmental Control Devices NO, Control Technology Micronized Coal Reburning Demonstration for NO, Control Project completed. Participant New York State Electric & Gas Corporation Additional Team Members Eastman Kodak Company—host and cofunder CONSOL (formerly Consolidation Coal Company)— coal sample tester D.B. Riley—technology supplier Fuller Company—technology supplier Energy and Environmental Research Corporation (EER)—reburn system designer New York State Energy Research and Development Authority—cofunder Empire State Electric Energy Research Corporation— cofunder Locations Lansing, Tompkins County, NY (New York State Electric & Gas Corporation’s Milliken Station, Unit No. 1) Rochester, Monroe County, NY (Eastman Kodak Company’s Kodak Park Power Plant, Unit No. 15) Technology D.B. Riley’s MPS mill (at Milliken Station) and Fuller’s MicroMill™ (at Eastman Kodak) technologies for producing micronized coal Plant Capacity/Production Milliken Station: 148-MWe tangentially-fired boiler Kodak Park: 50-MWe cyclone boiler MicroMill is a trademark of the Fuller Company. LNCFS is a trademark of ABB Combustion Engineering, Inc. 5-58 — Program Update 1999 SYSTEM EXISTING COAL' HOPPER MICROFUEL SYSTEM EXISTING PULVERIZERS OVERFIRE AIR BOILER BURNOUT ZONE- NORMAL EXCESS AIR REBURNING ZONE— SLIGHTLY FUEL RICH- NO, REDUCED TON. PRIMARY COMBUSTION ZONE— REDUCED FIRING RATE Coal Pittsburgh seam bituminous, medium- to high-sulfur (3.2% sulfur and 1.5% nitrogen at Milliken and 2.2% sulfur and 1.6% nitrogen at Kodak Park) Project Funding Total project cost $9,096,486 100% DOE 2,701,011 30 Participant 6,395,475 70 Project Objective To achieve at least 50% NO, reduction with micronized coal reburning technology on a cyclone boiler; to achieve 25-35% NO, reduction with micronized coal reburning technology in conjunction with low-NO, burners on a tangentially-fired boiler; and to determine the effects of coal micronization on electrostatic precipitator (EPS) performance. Technology/Project Description The reburn coal, which can comprise up to 30% of the total fuel, is micronized (pulverized to achieve 85% below 325 mesh) and injected into a pulverized coal-fired fur- nace above the primary combustion zone. At the Milliken site, coal is reburned for NO, control using the following methods: (1) close-coupled overfire air (CCOFA) reburning in which the top burner of the LNCFS III™ burners are used for injecting the micronized coal, and the remaining burners and air ports are re-aimed; and (2) adjustment of the remaining burners and air ports for deep stage combustion by re-aiming them to create a fuel-rich inner zone and fuel-lean outer zone providing combustion air. At Kodak Park, the Fuller MicroMill™ is used to produce the micronized coal, reburn fuel is introduced above the cyclone combustor, and overfire air is employed to complete the combustion. Environmental Control Devices Calendar Year 1991 1992 1993 1994 3 4/1 2 3 4 1 2 3 4 1 2 3 9/91 7/92 Preaward project (CCT-IV) 9/12/91 NEPA process completed (CX) 8/13/92 Cooperative agreement awarded 7/28/92 Design and Construction | Project relocated to Lansing and Rochester 12/95 DOE selected Ground breaking/construction started (Lansing) 3/15/96 Ground breaking/construction started (Rochester) 9/8/96 Design completed (Rochester) 9/96 Construction completed (Lansing) 1/97 Preoperational tests initiated (Rochester) 1/97 Construction completed (Rochester) 1/97 Preoperational tests initiated (Lansing) 1/97 Operation t Project completed/final report issued 12/99* Operation completed (Lansing) 4/99 Operation completed (Rochester) 10/98 Environmental monitoring plan completed (Lansing) 8/97 Operation initiated (Lansing) 3/97 Operation initiated (Rochester) 4/97 Results Summary Environmental + Using a 14% reburn fuel heat input on the Milliken Station tangentially-fired (T-fired) boiler resulted in a NO, emission rate of 0.25 1b/10° Btu, which represents a 28% NO, reduction. + Using a 17% reburn fuel heat input on the Kodak Park cyclone boiler resulted in a NO, emission rate of 0.60 Ib/10° Btu, which represents a 59% NO, reduction. Operational * Testing on the T-fired boiler at Milliken Station showed: — Unburned carbon-in-ash, also referred to as loss-on- ignition (LOI), was maintained under 4%, which is below the 4.5% maximum LOI for marketable fly ash; — Excess air is the single most important parameter that affects NO, emissions; Environmental Control Devices — Increasing coal fineness only marginally improved NO, emissions; and — Increasing the percent of reburn fuel slightly de- creased NO., but increased LOI. Testing on the cyclone boiler at Kodak Park showed: — Increasing reburn fuel rates resulted in lower NO, emissions; — NO, emission reductions on micronized coal were comparable to NO, reductions achieved with gas reburning; — LOI increased with the reburn system in opera- tion—LOI was 35-45% during full load (compared to a baseline of 10-12% without reburning); and — Stoichiometric ratios needed in the primary com- bustion zone and the reburn zone were 1.05—1.15 and 0.9, respectively. Environmental monitoring plan completed (Rochester) 8/97 “Projected date Economic ¢ Final results are not yet available, but in general, the capital cost of a micronized coal reburning system exceeds that of a gas reburning system due to milling system costs. On the other hand, the operating cost of a micronized coal reburning system is much lower than a gas reburning system because of the reburn fuel cost differential. Program Update 1999 5-59 Project Summary NYSEG demonstrated the micronized coal reburning technology in both tangentially-fired and cyclone-fired boilers. The T-fired boiler was NYSEG’s Milliken Sta- tion (also the host for another CCT Program demonstra- tion), 148-MWe Unit No. 1. The cyclone-fired boiler was Eastman Kodak Company’s Kodak Park Power Plant, 50-MWe Unit No. 15. The challenge with this coal reburning demonstration was to achieve adequate combustion of the reburn coal in the oxygen deficient, short residence time reburn zone to reduce NO, emissions without detrimentally increasing the unburned carbon in the ash, i.e., loss-on-ignition. The primary objective of this two-site project was to demon- strate improvements in coal reburning for NO, emission control by reducing the particle size of the reburn coal. In this demonstration, the coal was finely ground to 85% below 325 mesh and injected into the boilers above the primary combustion zone. The resulting typical particle size is 20 microns, compared to 60 microns for normal pulverized coal particles. This smaller size increases surface area ninefold. With this increased surface area and coal fineness, micronized coal has the combustion characteristics of atomized oil, which allows carbon com- bustion in milliseconds and release of volatiles at an even rate. Furthermore, reburning micronized coal combined with fuel/air staging results in more uniform, compact combustion in a smaller furnace volume compared to conventional pulverized coal, thus preventing furnace derating often associated with other NO, control tech- niques. Operating Performance At the Milliken Station, the existing ABB Low-NO, Concentric Firing System™ (LNCFS-III), which includes both close coupled and separated overfire air (OFA) ports, was used for the reburn demonstration. Four D.B. Riley MPS 150 mills with dynamic classifiers provided the pulverized coal. With LNCFS-III, there are four levels of burners. To simulate and test the reburning application, 5-60 Program Update 1999 the top-level burner nozzles fed micronized coal to the upper part of the furnace for this demonstration. The lower three burner nozzles were biased to carry approxi- mately 80% of the fuel required for full load, with the top burner supplying the remaining fuel. The speed of the dynamic classifier serving the mill feeding the top burners was increased to produce the micronized coal. At Kodak Park, EER designed the micronized coal reburn system using a combination of analytical and empirical techniques. The reburn fuel and OFA injection components were designed with a high degree of flexibil- ity to allow for field optimization to accommodate the complex furnace flow patterns in the cyclone boiler. A Fuller MicroMill™ produced the micronized coal reburn fuel with a particle size of about 20 microns. To maxi- mize NO, reduction, the reburn fuel was injected with flue gas rather than air. The flue gas was extracted down- stream of the electrostatic precipitator and boosted by a single fan. Two Fuller MicroMills™ were installed in parallel on Kodak Park Unit 15 to provide the capacity necessary for high reburn rates, the second mill serving as a spare at lower reburn rates. Eight injectors, six on the rear wall and one on each of the side walls, introduced the micron- ized coal into the reburn zone. The optimization variables included the number of injectors, swirl, and velocity. Four injectors on the front wall provided OFA using EER’s second generation, dual-concentric OFA air de- sign, which has variable injection velocity and swirl. A new boiler control system was also installed on Unit No. 15. Some mechanical problems were encountered during the demonstration, including plugging of the coal han- dling system that feeds the MicroMill™, vibration and blade wear on the mills, erosion of the classifiers, and corrosion due to low temperature flue gas when the reburn system was out of service. These problems were corrected and successful operation was achieved. Environmental Performance At the Milliken Station, micronized coal reburning with 14% reburn fuel reduced NO, from 0.35 Ib/10° Btu base- line level to 0.25 Ib/10° Btu, a 28% reduction, which is within the target range of 25-35% reduction. A primary objective at Milliken was to determine the minimum NO, level attainable while maintaining market- able fly ash (fly ash having less than 4.5% carbon). Vari- ables studied at Milliken included boiler load, reburn coal fineness, oxygen level at the economizer, percent reburn fuel, main burner tilt, and OFA tilt. During the testing, NYSEG found that excess air was the single most impor- tant parameter that affects NO, emissions. As shown in Exhibit 5-27, higher excess air results in higher NO, emissions, but lower LOI. In the case of the top mill (feeding reburning level) adjusted for regular grind (80% through 200 mesh), an increase in measured 0, at the economizer inlet from 2.5% to 3.75% yields an increase in NO, emissions from 0.36 Ib/10° Btu to 0.43 1b/106 Btu, or about a 20% increase. When the top mill is adjusted for fine grind (micronized), the NO, emissions are only mar- ginally better. Exhibit 5-27 also shows the dramatic impact of excess air on LOI. When the economizer O, is varied from 2.5% to 3.5%, the LOI will drop from 6.2% to 3.8% (39% reduction) for the case of the top mill adjusted for regular grind. When the same measurements are made while the top mill is micronizing, the reduction in LOI is less significant. Results from other parametric testing at Milliken revealed that increasing coal fineness improved NO, emissions only marginally, but lowered LOI. Other re- sults showed that increasing the percent reburn fuel slightly decreased NO_, but substantially increased LOI. At Kodak Park, micronized coal reburning with 17% reburn fuel reduced NO, emissions to 0.60 1b/10° Btu from a baseline of 1.45 Ib/10° Btu, a 59% reduction. At greater reburn rates, further NO, reduction was achieved to a degree comparable with gas reburning systems. As Environmental Control Devices expected, LOI increased with the reburn system in operation. At full load LOI was 35-45%, as compared to a baseline level of 10-12%. Economic Performance Although economic data are not available, the demon- stration showed that micronized coal reburning has the potential for significantly lower NO, control costs than gas reburning. With gas reburning, the differential cost of gas over coal is the largest component of the cost of NO, reduction. This differential is zero when micron- ized coal is used as the reburn fuel. However, the capi- tal cost of coal reburning is higher than gas reburning Exhibit 5-27 Parametric Testing Results 8 7 Top Mill Regular Grind x “6 5 L J 5k 4 L <s o4b x 3, Top Mill Fine Grind 2 0.45 [ Top Mill Regular Grind 2 040 b = b S 035 b 2 L , x 030 L Top Mill Fine Grind 3s Log B 025 L 5 L 2 0.20 ° 42 0.15 | 20 25 30 35 40 45 5.0 | Economizer O,, % Environmental Control Devices due to the capital and operating costs of coal milling system and other coal-handling equipment. Commercial Applications Micronized coal reburning technology can be applied to existing and greenfield cyclone-fired, wall-fired, and tangentially-fired pulverized coal units. The technology reduces NO, emissions by 20-59% with minimal furnace modifications for existing units. The availability of a coal-reburning fuel, as an addi- tional fuel to the furnace, enables switching to lower heating value coals without boiler derating. Reburn burn- ers also can serve as low-load burners, and commercial units can achieve a turndown of 8:1 on nights and week- ends without consuming expensive auxiliary fuel. Contacts Jim Harvilla, (607) 762-8630 New York State Electric & Gas Corporation Corporate Drive-Kirkwood Industrial Park P.O. Box 5224 Binghamton, NY 13902-5224 (607) 762-8457 (fax) Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, NETL, (412) 386-5991 References * Reburning Technologies for the Control of Nitro- gen Oxides from Coal-Fired Boilers. (U.S. Depart- ment of Energy, Babcock & Wilcox, EER Corp., and NYSEG) Topical Report No. 14. May 1999. * Savichky et al. “Micronized Coal Reburning Dem- onstration of NO, Control.” Sixth Clean Coal Tech- nology Conference: Technical Papers. April-May 1998. Program Update 1999 5-61 Environmental Control Devices NO, Control Technology Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High- Sulfur, Coal-Fired Boilers Project completed. Participant Southern Company Services, Inc. Additional Team Members Electric Power Research Institute—cofunder Ontario Hydro—cofunder Gulf Power Company—host Location Pensacola, Escambia County, FL (Gulf Power Company’s Plant Crist, Unit No. 4) Technology Selective catalytic reduction (SCR) Plant Capacity/Production 8.7-MWe equivalent (three 2.5-MWe and six 0.2-MWe equivalent SCR reactor plants) Coal Illinois bituminous, 2.7% sulfur Project Funding Total project cost $23,229,729 100% DOE 9,406,673 40 Participant 13,823,056 60 Project Objective To evaluate the performance of commercially available SCR catalysts when applied to operating conditions found in U.S. pulverized coal-fired utility boilers using high- sulfur U.S. coal under various operating conditions while achieving as much as 80% NO, removal. 5-62 Program Update 1999 BOILER ECONOMIZER BYPASS AMMONIA | INJECTION ASH SCR REACTOR ELECTROSTATIC PRECIPITATOR AIR PREHEATER STACK TO DISPOSAL Technology/Project Description The SCR technology consists of injecting ammonia into boiler flue gas and passing it through a catalyst bed where the NO, and ammonia react to form nitrogen and water vapor. In this demonstration project, the SCR facility con- sisted of three 2.5-MWe equivalent SCR reactors, sup- plied by separate 5,000 scfm flue gas slipstreams, and six 0.20-MWe equivalent SCR reactors. These reactors were calculated to be large enough to produce design data that will allow the SCR process to be scaled up to commercial size. Catalyst suppliers (two U.S., two European, and two Japanese) provided eight catalysts with various shapes and chemical compositions for evaluation of pro- cess chemistry and economics of operation during the demonstration. The project demonstrated, at high- and low-dust loadings of flue gas, the applicability of SCR technology to provide a cost-effective means of reducing NO, emis- sions from power plants burning high-sulfur U.S. coal. The demonstration plant, which was located at Gulf Power Company’s Plant Crist near Pensacola, FL, used flue gas from the burning of 2.7% sulfur coal. Environmental Control Devices Results Summary Environmental Calendar Year 1988 Preaward NEPA process completed (MTF) 8/16/89 Cooperative agreement DOE selected project ant a awarded 6/14/90 (CCT-Il) 9/28/88 NO, reductions of over 80% were achieved at an am- monia slip well under the 5 ppm deemed acceptable for commercial operation. Flow rates could be increased to 150% of design with- out exceeding the ammonia slip design level of 5 ppm at 80% NO, reduction. While catalyst performance increased above 700 °F, the benefit did not outweigh the heat rate penalties. Increases in ammonia slip, a sign of catalyst deactiva- tion, went from less than | ppm to approximately 3 ppm over the nearly 12,000 hours of operation, thus demonstrating deactivation in coal-fired units was in line with worldwide experience. Long-term testing showed that SO, oxidation was within or below the design limits necessary to protect downstream equipment. Environmental Control Devices Design and Construction Operational Operation Project completed/final Operation initiated 7/93 report issued 11/96 Operation completed 7/95 Preoperational tests initiated 3/93 Environmental monitoring plan completed 3/11/93 Construction completed 2/93 Design completed 12/92 Ground breaking/construction started 3/92 Economic Fouling of catalysts was controlled by adequate soot- blowing procedures. + Levelized costs for various NO, removal levels for a 250-MWe unit at 0.35 Ib/10° Btu inlet follow: Long-term testing showed that catalyst erosion was not 40% 60% 80% a problem. 1996 levelized cost Air preheater performance was degraded because of (mills/kWh) 2.39 2.57 2.79 ammonia slip and subsequent by-product formation; 1996 levelized cost however, solutions were identified. ($/ton) 3,502 2,500 ~—-.2,036 The SCR process did not significantly affect the results of Toxicity Characteristic Leaching Procedure analysis of the fly ash. Program Update 1999 5-63 Project Summary The demonstration tests were designed to address several uncertainties, including potential catalyst deactivation due to poisoning by trace metals species in U.S. coals, perfor- mance of technology and effects on the balance-of-plant equipment in the presence of high amounts of SO, and SO,, and performance of the SCR catalyst under typical U.S. high-sulfur coal-fired utility operating conditions. Catalyst suppliers were required to design the catalyst baskets to match predetermined reactor dimensions, pro- vide a maximum of four catalyst layers, and meet the following reactor baseline conditions: Parameter Minimum Baseline Maximum Temperature (°F) 620 700 750 NH,/NO, molar ratio 0.6 0.8 1.0 Space velocity (1% design flow) 60 100 150 Flow rate (scfm) Large reactor 3,000 5,000 7,500 Small reactor 240 400 600 The catalysts tested are listed in Exhibit 5-28. Cata- lyst suppliers were given great latitude in providing the amount of catalyst for this demonstration. Environmental Results Ammonia slip, the controlling factor in the long-term operation of commercial SCR, was usually <5 ppm be- cause of plant and operational considerations. Ammonia slip was dependent on catalyst exposure time, flow rate, temperature, NH,/NO, distribution, and NH,/NO, ratio (NO, reduction). Changes in NH,/NO, ratio and conse- quently NO, reduction generally produced the most sig- nificant changes in ammonia slip. The ammonia slip at 60% NO, reduction was at or near the detection limit of 1 ppm. As NO, reduction was increased above 80%, ammonia slip also increased and remained at reasonable levels up to NO, reductions of 90%. Over 90%, the am- monia slip levels increased dramatically. The flow rate and temperature effects on NO, reduc- tion were also measured. In general, flows could be in- 5-64 Program Update 1999 Exhibit 5-28 Catalysts Tested Catalyst Reactor Size* Catalyst Configuration Nippon/Shokubai Large Honeycomb Siemens AG Large Plate W.R. Grace/Noxeram Large Honeycomb W.R. Grace/Synox Small Honeycomb Haldor Topsoe Small Plate Hitachi/Zosen Small Plate Cormetech/High dust Small Honeycomb Cormetech/Low dust Small Honeycomb * Large = 2.5-MWe; 5,000 scfm Small = 0.2-MWe; 400 scfm creased to 150% of design without the ammonia slip exceeding 5 ppm, at 80% NO, reduction and design tem- perature. With respect to temperature, most catalysts exhibited fairly significant improvements in overall per- formance as temperatures increased from 620 °F to 700 °F, but relatively little improvement as temperature increased from 700 °F to 750 °F. The conclusion was that the benefits of high-temperature operation probably do not outweigh the heat rate penalties involved in operating SCR at the higher temperatures. Catalyst deactivation was generally observed by an increase in ammonia slip over time, assuming the NO. reduction efficiency was held constant. Over the 12,000 hours of the demonstration tests, the ammonia slip did increase from less than | ppm to approximately 3 ppm. These results demonstrated the maturity of catalyst design and that deactivation was in line with prior worldwide experience. Experience has shown that the catalytic active spe- cies that result in NO, reduction often contributed to SO, oxidation (i.e., SO, formation), which can be detrimental to downstream equipment. In general, NO, reduction can be increased as the tolerance for SO, is also increased. The upper bound for SO, oxidation for the demonstration catalyst was set at 0.75% at baseline conditions. The average SO, oxidation rate for each of the catalysts is shown in Exhibit 5-29. These data reflect baseline condi- tions over the life of the demonstration. All of the cata- lysts were within design limits, with most exhibiting oxidation rates below the design limit. Other factors affecting SO, oxidations were flow rate and temperature. Most of the catalysts exhibited fairly constant SO, oxidation with respect to flow rate (i.e., space velocity). In theory, SO, oxidation should be in- versely proportional to flow rate. Theoretically, the rela- tionship between SO, oxidation and temperature should be exponential as temperature increases; however, mea- surements showed the relationship to be linear with little difference in SO, oxidation between 620 °F and 700 °F. On the other hand, between 700 °F and 750 °F, the SO, oxidation increased more significantly. Other findings from the demonstration deal with pressure drop, fouling, erosion, air preheater performance, Exhibit 5-29 Average SO, Oxidation Rate (Baseline) Average SO, Oxidation (%) 12 High 1.0 Average Low 08 base-line design value 0.6 04 | 7 TT 02 + o [i + Noxeram Siemens Corm. HD Hitachi NSKK Synox Haldor Corm. LD NH,/NO, = 0.8, 700 °F, design flow Environmental Control Devices ammonia volatilization, and toxicity characteristic leach- ing procedure (TCLP) analysis. Overall reactor pressure drop was a function of the catalyst geometry and volume, but tests to determine which one was controlling were inconclusive. The fouling characteristics of the catalyst were important to long-term operation. During the dem- onstration, measurements showed relatively level pressure drop over time, indicating that sootblowing procedures were effective. The plate-type configurations had some- what less fouling potential than did the honeycomb con- figuration, but both were acceptable for application. Catalyst erosion was not considered to be a significant problem because most of the erosion was attributed to aggressive sootblowing. With regard to air preheater performance, the demonstration showed that the SCR process exacerbated performance degradation of the air preheaters mainly due to ammonia slip and subsequent by-product formation. Regenerator-type air heaters out- performed recuperators in SCR applications in terms of both thermal performance and fouling. The ammonia volatilized from the SCR flyash when a significant amount of water was absorbed by the ash. This was caused by formation of a moist layer on the ash with a pH high enough to convert ammonia compounds in the ash to gas-phase ammonia. TCLP analyses were performed on flyash samples. The SCR process did not significantly affect the toxics leachability of the fly ash. Economic Results An economic evaluation was performed for full-scale applications of SCR technology to a new 250-MWe pul- verized coal-fired plant located in a rural area with mini- mal space limitations. The fuel considered was high- sulfur Illinois No. 6 coal. Other key base case design criteria are shown in Exhibit 5-30. Results of the economic analysis of capital, operating and maintenance (O&M), and levelized cost based on a 30-year project life for various unit sizes for an SCR system with a NO, removal efficiency of 60% follow: Environmental Control Devices 125-MWe 250-MWe 700-MWe Capital cost ($/kW) 61 54 45 Operating cost ($) 580,000 1,045,000 2,667,000 1996 levelized cost mills/kWh 2.89 2.57 2.22 $/ton 2,811 2,500 2,165 Results of the economic analysis of capital, O&M, and levelized cost for various NO, removal efficiencies for a 250-MWe unit with 0.35 1b/10° Btu of inlet NO, are as follows: 40% 60% 80% Capital cost (S/kW) 52 54 57 Operating costs ($) 926,000 1,045,000 1,181,000 1996 levelized cost mill/kWh $/ton 2.39 3,502 2.57 2,500 2.79 2,036 For retrofit applications, the estimated capital costs were $59—-112/kW, depending on the size of the installa- Exhibit 5-30 Design Criteria Parameter Specification Type of SCR Hot side Number of reactors One Reactor configuration 3 catalyst support layers Initial catalyst load 2 of 3 layers loaded Range of operation 35-100% boiler load NO, inlet concentration 0.35 1b/10° Btu Design NO, reduction 60% Design ammonia slip 5 ppm Catalyst life 16,000 hr Ammonia cost $250/ton SCR cost $400/ft tion and the difficulty and scope of the retrofit. The levelized costs for the retrofit applications were $1,850-5,100/ton (1996$). Commercial Applications As a result of this demonstration, SCR technology has been shown to be applicable to existing and new utility generating capacity for removal of NO, from the flue gas of virtually any size boiler. There are over 1,000 coal- fired utility boilers in active commercial service in the United States; these boilers represent a total generating capacity of approximately 300,000 MWe. Contacts Larry Monroe, (205) 257-7772 Southern Company Services, Inc. P.O. Box 2641 Birmingham, AL 35291-8195 (205) 257-5367 (fax) Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, NETL, (412) 386-5991 References * Control of Nitrogen Oxide Emissions: Selective Cata- lytic Reduction (SCR). Topical Report No. 9. U.S. Department of Energy and Southern Company Ser- vices, Inc. July 1997. * Maxwell, J. D., et al. “Demonstration of SCR Tech- nology for the Control of NO, Emissions from High- Sulfur Coal-Fired Utility Boilers.” Fifth Annual Clean Coal Technology Conference: Technical Papers, January 1997. * Demonstration of SCR Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Utility Boilers: Final Report. Vol. 1. Southern Company Services, Inc. October 1996. (Available from NTIS, Vol. 1 as DE97050873, Vol. 2: Appendixes A-N as DE97050874, and Vol. 3: Appendixes O-T as DE97050875.) Program Update 1999 5-65 Environmental Control Devices NO, Control Technology 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers Project completed. Participant Southern Company Services, Inc. Additional Team Members Gulf Power Company—cofunder and host Electric Power Research Institute—cofunder ABB Combustion Engineering, Inc.—cofunder and technology supplier Location Lynn Haven, Bay County, FL (Gulf Power Company’s Plant Lansing Smith, Unit No. 2) Technology ABB Combustion Engineering’s Low-NO, Concentric Firing System (LNCFS™) with advanced overfire air (AOFA), clustered coal nozzles, and offset air Plant Capacity/Production 180-MWe Coal Eastern bituminous, high reactivity Project Funding Total project cost $8,553,665 100% DOE 4,149,382 49 Participant 4,404,283 51 LNCFS is a trademark of ABB Combustion Engineering, Inc. 5-66 Program Update 1999 BOILER ECONOMIZER ADVANCED OVERFIRE AIR ELECTROSTATIC ELECTROSTATIC PORTS PRECIPITATOR PRECIPITATOR COMBUSTION AIR oS AIR + AOFAPORTS +—— WINDBOX WINDBOX ab \ bh. PULVERIZED__. [+—PULVERIZED COAL _.4f * Fi<— COAL im : | DRY WASTE TO DISPOSAL CONCENTRIC. FIRING SYSTEM CONCENTRIC FIRING SYSTEM ASH Project Objective fire air system that incorporates back pressuring and flow To demonstrate in a stepwise fashion the short- and long- measurement capabilities. CCOFA and SOFA were both term NO, reduction capabilities of LNCFS™ levels I, II, used in the LNCFS™ III tangential-firing approach. and III on a single reference boiler. Carefully controlled short-term tests were conducted Technology/Project Description followed by long-term testing under normal load dispatch Technologies demonstrated included LNCFS™ levels I, II, and III. Each level of the LNCFS™ used different combinations of overfire air and clustered coal nozzle conditions. Long-term tests, which typically lasted 2-3 months for each phase, best represent the true emissions characteristics of each technology. Results presented are aoe : : . based on long-term test data. positioning to achieve NO, reductions. With the 6 LNCFS™, primary air and coal are surrounded by oxy- gen-rich secondary air that blankets the outer regions of the combustion zone. LNCFS™ I used a close-coupled overfire air (CCOFA) system integrated directly into the windbox of the boiler. A separated overfire air (SOFA) system located above the combustion zone was featured in the LNCFS™ II system. This was an advanced over- Environmental Control Devices Calendar Year 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4;)/1 2 3 4/1 2 3 4/1 2 3 4/ 1 «2 9/88 9/90 Preaward Operation li selected Operation initiated 5/91 project C . | (CCT-II) onstruction Operation completed 12/92 9/28/88 completed 5/91 NEPA process Design completed 4/91 completed (MTF) 7/21/89 Environmental monitoring plan completed 12/27/90 Cooperative agreement awarded 9/20/90 Ground breaking/construction started 11/90 Project completed/final report issued 6/94 Results Summary Environmental + At full load, the NO, emissions using LNCFS™ I, II, and III were 0.39, 0.39, and 0.34 Ib/10° Btu, respec- tively, which represent reductions of 37, 37, and 45% from the baseline emissions. * Emissions with LNCFS™ were not sensitive to power outputs between 100- and 200-MWe, but emissions increased significantly below 100-MWe, reaching baseline emission levels at 70-MWe. * Because of reduced effectiveness at low loads, LNCFS™ proved marginal as a compliance option for peaking load conditions. + Average CO emissions increased at full load. * Air toxics testing found LNCFS™ to have no clear-cut effect on the emissions of trace metals or acid gases. Volatile organic compounds (VOCs) appeared to be reduced and semi-volatile compounds increased. Environmental Control Devices Operational + Loss-on-ignition (LOI) was not sensitive to the LNCFS™ retrofits but very sensitive to coal fineness. * Furnace slagging was reduced but backpass fouling was increased for LNCFS™ II and III. * Boiler efficiency and unit heat rate were impacted minimally. + Unit operation was not significantly affected, but oper- ating flexibility of the unit was reduced at low loads with LNCFS™ II and III. Economic The capital cost estimate for LNCFS™ I was $5-15/kW and for LNCFS™ II and III, $15—25/kW (19938). The cost effectiveness for LNCFS™ I was $103/ton of NO, removed; LNCFS™ II, $444/ton; and LNCFS™ III, $400/ton (1993$). Program Update 1999 Project Summary LNCFS™ technology was designed for tangentially-fired boilers, which represent a large percentage of the pre- NSPS coal-fired generating capacity. The technology reduces NO, by staging combustion in the boiler verti- cally by separating coal and air injectors and horizontally by creating fuel-rich and lean zones with offset air nozzles. The objective was to determine NO, emission reductions and impact on boiler performance over the long-term under normal dispatch and operating condi- tions. By using the same boiler, the demonstration pro- vided direct comparative performance analysis of the three configurations. Short-term parametric testing en- abled extrapolation of results to other tangentially-fired units by evaluating the relationship between NO, emis- sions and key operating parameters. At the time of the demonstration, specific NO, emis- sion regulations were being formulated under the CAAA. The data developed over the course of this project pro- vided needed real-time input to regulation development. Exhibit 5-31 shows the various LNCFS™ configu- rations used to achieve staged combustion. In addition to overfire air, the LNCFS™ incorporates other NO, -reduc- ing techniques into the combustion process as shown in Exhibit 5-32. Using offset air, two concentric circular combustion regions are formed. The majority of the coal is contained in the fuel-rich inner region. This region is surrounded by a fuel-lean zone containing combustion air. The size of this outer annulus of combustion air can be varied using adjustable offset air nozzles. Operational Performance Exhibit 5-33 summarizes the impacts of LNCFS™ on unit performance. Environmental Performance At full load, LNCFS™ I, II, and III reduced NO, emis- sions by 37, 37, and 45%, respectively. Exhibit 5-34 presents the NO, emission estimates obtained in the as- sessment of the average annual NO, emissions for three dispatch scenarios. 5-68 Program Update 1999 Exhibit 5-31 LNCFS™ Configurations Exhibit 5-32 Concentric Firing Concept Separated EF] Separated Overtire Air L} Overfire Air Hi EHH Air Air Close- : Close- Coupled Coal Coupled “oa i cr ‘al cone Coal OverfireAir Air £] Offset Air Coal + Coal Air £] Offset Air Coal Coal Coal Coal { Air LH Offset Air Offset Air Offset Air HEH Air FH ontset Air HEH Offset Air EEE] Offset Air Coal Coal Coal | coat HEH Air Offset Air EE] Offset Air FH Offset Air H Air 1] Offset Air FEY Offset Air ++} Offset Air Coal Coal Coal Coal Air Offset Air ELH oftset air Offset Air tH set / Offset Air Air HEH oftset Air Offset Air Coal Coal Coal Coal Air LED air COED air Air BASELI INE LNCFS I LNCFS IL LNCFS Ill Fuel-Rich Zone Burner Air toxics testing found LNCFS™ to have no clear- cut effect on the emission of trace metals or acid gases. The data provided marginal evidence for a decreased emission of chromium. The effect on aldehydes/ketones could not be assessed because baseline data were compro- mised. VOCs appeared to be reduced and semi-volatile compounds increased. The increase in semi-volatile compounds was deemed to be consistent with increases in the amount of unburned carbon in the ash. Economic Performance LNCFS™ II was the only complete retrofit (LNCFS™ I and III were modifications of LNCFS™ II), and therefore capital cost estimates were based on the Lansing Smith Unit No. 2 retrofit as well as other tangentially-fired LNCFS™ retrofits. The capital cost ranges in 1993 con- stant dollars follow: ¢« LNCFS™ I—$5-15/kW * LNCFS™ II—$15-25/kW ¢ LNCFS™ III—$15-25/kW Site-specific considerations have a significant effect on capital costs; however, the above ranges reflect actual experience and are planning estimates. The actual capital cost for LNCFS™ II at Lansing Smith Unit No. 2 was $3 million, or $17/kW, which falls within the projected range. The cost effectiveness of the LNCFS™ technologies is based on the capital and operating and maintenance costs and the NO, removal efficiency of the technologies. The cost effectiveness of the LNCFS™ technologies follows (based on a levelization factor of 0.144 in 1993 constant dollars): Environmental Control Devices + LNCFS™ I—$103/ton of NO, removed + LNCFS™ II—$444/ton of NO, removed + LNCFS™ III—$400/ton of NO, removed Commercial Applications LNCFS™ technology has potential commercial applica- tion to all the nearly 600 U.S. pulverized coal, tangen- tially-fired utility units. These units range from 25-MWe to 950-MWe in size and fire a wide range of coals, from low-volatile bituminous through lignite. LNCFS™ has been retained at the host site for com- mercial use. ABB Combustion Engineering has modi- fied 116 tangentially-fired boilers, representing over 25,000 MWe, with LNCFS™ and derivative TFS 2000™ burners. Contacts Larry Monroe, (205) 257-7772 Southern Company Services, Inc. P.O. Box 2641 Birmingham, AL 35291-8195 (205) 257-5367 (fax) Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, NETL, (412) 386-5991 References + 180-MWe Demonstration of Advanced Tangen- tially-Fired Combustion Techniques for the Reduction of Nitrogen Oxide (NO) Emissions from Coal-Fired Boilers: Final Report and Key Project Findings. Report No. DOE/PC/89653-T14. Southern Company Services, Inc. February 1994. (Available from NTIS as DE9401 1174.) + 180-MWe Demonstration of Advanced Tangen- tially-Fired Combustion Techniques for the Reduc- tion of Nitrogen Oxide (NO) Emissions from Coal- Fired Boilers—Plant Lansing Smith—Phase III and Final Environmental Monitoring Program Report. Southern Company Services, Inc. December 1993. Environmental Control Devices Exhibit 5-33 Unit Performance Impacts Based on Long-Term Testing Baseline LNCFS™ | LNCFS™ Il LNCFS"™ Ill Avg CO at full load (ppm) 10 12 22 33 Avg excess O, at full load (%)3.7 3.2 4.5 4.3 LOL at full load (%) 4.8 4.6 4.2 5.9 0, (%) 4.0 3.9 5.3 47 Steam outlet conditions Satisfactory at full load; low temper- atures at low loads Full load: S—10 °F lower than baseline Low loads: 10-30 °F lower than baseline Same as baseline 160- to 200-MWe: satisfactory 80-MWe: 15-35 °F lower than baseline Furnace slagging and Medium Medium Reduced slagging, Reduced slagging, backpass fouling but increased fouling but increased fouling Operating flexibility Normal Same as baseline More care required — More difficult to at low loads operate than other systems Boiler efficiency (%) 90 90.2 89.7 89.85 Efficiency change N/A +0.2 -0.3 -0.15 Turbine heat rate (Btu/kWh) 9,000 9,011 9,000 9,000 Unit net heat rate (Btu/kWh) 9,995 9,986 10,031 10,013 Change (%) N/A -0.1 +0.36 +0.18 Exhibit 5-34 Average Annual NO, Emissions and Percent Reduction Boiler Duty Cycle Units Baseline LNCFS™1 LNCFS™ || LNCFS™ Ill Baseload Avg NO, emissions (Ib/10° Btu) 0.62 0.41 0.41 0.36 (161.8-MWe avg) Avg reduction (%) 38.7 38.7 42.2 Intermediate load Avg NO, emissions (Ib/10° Btu) 0.62 0.40 0.41 0.34 (146.6-MWe avg) Avg reduction (%) 39.2 35.9 45.3 Peaking load Avg NO, emissions (Ib/10° Btu) 0.59 0.45 0.47 0.43 (101.8-MWe avg) Avg reduction (%) 36.1 20.3 28.0 Program Update 1999 5-69 Environmental Control Devices Combined SO,/NO_ Control Technologies Environmental Control Devices Combined SO,/NO, Control Technology Commercial Demonstration of the NOXSO SO./NO, Removal Flue Gas Cleanup System Participant NOXSO Corporation Additional Team Members Olin Corporation—cofunder Gas Research Institute—cofunder Electric Power Research Institute—cofunder W.R. Grace and Company—cofunder M.K. Ferguson—engineer Richmond Power & Light (RP&L)—host Location To be determined Technology NOXSO Corporation’s dry, regenerable flue gas cleanup process Plant Capacity/Production To be determined Coal Medium- to high-sulfur coals Project Funding Total project cost DOE Participant $82,812,120 41,406,060 41,406,060 100% 50 50 Project Objective To demonstrate removal of 98% of the SO, and 75% of the NO, from a coal-fired boiler’s flue gas using the NOXSO process. 5-72 Program Update 1999 CLEAN FLUE GAS BOILER DIRTY TO STACK FLUE ‘ BAGHOUSE GAS ELECTROSTATIC ASH NO, RECYCLE | PRECIPATOR | L. t y ’ COAL AIR DISPOSAL FLUIDIZED-BED} ADSORBER ag cae MAKEUP SORBENT) SULFUR RECOVERY UNIT SULFUR Technology/Project Description The NOXSO process is a dry, regenerable system capable of removing both SO, and NO, in flue gas from coal-fired utility boilers burning medium- to high-sulfur coals. In the basic process, the flue gas passes through a fluidized- bed adsorber located downstream of the precipitator; SO, and NO, are adsorbed by the sorbent, which consists of spherical beads of high-surface-area alumina impregnated with sodium carbonate. Cleaned flue gas then passes through a baghouse to the stack. The NO, is desorbed from the NOXSO sorbent when heated by a stream of hot air. Hot air containing the desorbed NO, is recycled to the boiler where equilibrium processes cause destruction of the NO... The adsorbed sulfur is recovered from the sorbent in a regenerator where it reacts with methane at high temperature to pro- duce an offgas with high concentrations of SO, and hy- drogen sulfide (H,S). This offgas is processed to produce elemental sulfur, which can be further processed to pro- duce liquid SO,, a higher valued by-product. The process is expected to achieve SO, reductions of 98% and NO, reductions of 75%. Environmental Control Devices Calendar Year 1989 1990 1991 1992 3 4/1 2 3 4/1 2 3 4)1 2 3 3° 4;/1 2 3 4/1 1996 2 3 12/89 3/91 Preaward Cooperative agreement awarded 3/11/91 DOE selected project (CCT-III) 12/19/89 Project Status/Accomplishments Alcoa Generating Corporation chose to cancel a host site agreement when NOXSO was unable to obtain full project financing by January 31, 1997, as specified in the agreement. NOXSO signed a conditional Host Site Agreement with RP&L in January 1998. NOXSO filed for bankruptcy under Chapter 11 - Reorganization. The Chapter 11 plan was approved by the Bankruptcy Court on September 2, 1998, but NOXSO was unable to raise sufficient funds. NOXSO closed its office in October 1998. By order of the bankruptcy court, NOXSO’s second amended plan of reorganization under Chapter 11 was approved on December 9, 1999. One of the provisions of the approved plan was the rejection of the cooperative agreement; as a result, the cooperative agreement was terminated. Prior to publication of this report, the project ended in December 1999 in accordance with the order of the Bankruptcy Court. Environmental Control Devices Design Novation of cooperative agreement with NOXSO Corp. 8/94 Selected Alcoa host site 8/94 Project definition phase completed 10/94 NEPA process completed, Alcoa (EA) 6/26/95 Commercial Applications The NOXSO process is applicable to existing or new facilities. The process is suitable for utility and industrial coal-fired boilers. The process is adaptable to coals with medium- to high-sulfur content. The process produces one of the following as a sal- able by-products: elemental sulfur, sulfuric acid, or liquid SO,. A readily available market exists for these products. The technology is expected to be especially attractive to utilities that require high removal efficiencies for both SO, and NO,, need to eliminate solid wastes, and/or have inadequate water supply for a wet scrubber. On Hold Schedule pending action in bankruptcy court Identified conditional host site, RP&L 1/98 Alcoa Generating Corp. cancelled host site agreement 2/97 Program Update 1999 5-73 Environmental Control Devices Combined SO,/NO, Control Technology SNOX™ Fiue Gas Cleaning Demonstration Project Project completed. Participant ABB Environmental Systems Additional Team Members Ohio Coal Development Office—cofunder Ohio Edison Company—cofunder and host Haldor Topsoe a/s—patent owner for process technology, catalysts, and WSA Tower Snamprogetti, U.S.A.—cofunder and process designer Location Niles, Trumbull County, OH (Ohio Edison’s Niles Sta- tion, Unit No. 2) Technology Haldor Topsoe’s SNOX™ catalytic advanced flue gas cleanup system Plant Capacity/Production 35-MWe equivalent slipstream from a 108-MWe boiler Coal Ohio bituminous, 3.4% sulfur Project Funding Total project cost $31,438,408 100% DOE 15,719,200 50 Participant 15,719,208 50 Project Objective To demonstrate at an electric power plant using U.S. high-sulfur coals in which SNOX™ technology will catalytically remove 95% of SO, and more than 90% of NO, from flue gas and produce a salable by-product of concentrated sulfuric acid. SNOX is a trademark of Haldor Topsoe a/s. 5-74 Program Update 1999 BOILER AIR PREHEATER BAGHOUSE ; SUPPORT BURNER ASH ASH TO DISPOSAL COOLING AIR FLUE GAS ELECTROSTATIC | PRECIPITATOR STACK SUPPORT TO DISPOSAL BURNER CLEAN FLUE GAS HOT-AIR DISCHARGE CONDENSER (WSA TOWER) SULFURIC ACID FLUE GAS ACID CATALYTIC COLLECTOR 2 REACTOR SUPPORT - ACID STORAGE TANK Technology/Project Description In the SNOX™ process, the stack gas leaving the boiler is cleaned of fly ash in a high-efficiency fabric filter bag- house to minimize the cleaning frequency of the sulfuric acid catalyst in the downstream SO, converter. The ash- free gas is reheated, and NO, is reacted with small quanti- ties of ammonia in the first of two catalytic reactors where the NO, is converted to harmless nitrogen and water vapor. The SO, is oxidized to SO, in a second catalytic converter. The gas then passes through a novel glass-tube condenser that allows SO, to hydrolyze to concentrated sulfuric acid. The technology was designed to remove 95% of the SO, and more than 90% of the NO, from flue gas and produce a salable sulfuric acid by-product using U.S. coals. This was accomplished without using sorbents and without creating waste streams. The demonstration was conducted at Ohio Edison’s Niles Station in Niles, Ohio. The demonstration unit treated a 35-MWe equivalent slipstream of flue gas from the 108-MWe Unit No. 2 boiler, which burned a 3.4% sulfur Ohio coal. The process steps were virtually the same as for a full-scale commercial plant, and commer- cial-scale components were installed and operated. Environmental Control Devices Calendar Year 1988 1989 3 °4/1 2 3 4/1 2 3 4;/1 2 3 1998 9/88 12/89 Preaward Design and Construction 3/92 Operation 7/96 DOE selected project (CCT-II) 9/28/88 Cooperative agreement awarded 12/20/89 t Operation initiated 3/92 Construction completed 12/91 Preoperational tests initiated 12/91 Dedication ceremony held 10/17/91 Environmental monitoring plan completed 10/31/91 Design completed 8/91 Construction started 1/91 NEPA process completed (MTF) 1/31/90 | Project completed/ final report issued 7/96 Operation completed 12/94 Results Summary Environmental SO, removal efficiency was normally in excess of 95% for inlet concentrations averaging about 2,000 ppm. NO, reduction averaged 94% for inlet concentrations of approximately 500-700 ppm. Particulate removal efficiency for the high-efficiency fabric filter baghouse with SNOX™ system was greater than 99%, Sulfuric acid purity exceeded federal specifications for Class I acid. Air toxics testing showed high capture efficiency of most trace elements in the baghouse. A significant portion of the boron and almost all of the mercury escaped to the stack. But selenium and cadmium, normally a problem, were effectively captured in the acid drain, as were organic compounds. Absence of an alkali reagent contributed to having no secondary pollution streams or increases in CO, emissions. Environmental Control Devices Presence of the SO, catalyst virtually eliminated CO and hydrocarbon emissions. Operational Having the SO, catalyst downstream of the NO, cata- lyst eliminated ammonia slip and allowed the SCR to function more efficiently. Heat developed in the SNOX™ process was used to enhance thermal efficiency. Economic Capital cost was estimated at $305/kW for a 500-MWe unit firing 3.2% sulfur coal. The levelized incremental cost was estimated at 6.1 mills/kWh or $219/ton of SO, removal on a constant 1995 dollar basis. Comparable current dollar costs were 7.8 mills/ kWh and $284/ton of SO,. Program Update 1999 5-75 Project Summary No reagent was required for the SO, removal step because the SNOX™ process utilized an oxidation catalyst to convert SO, to SO, and ultimately to sulfuric acid. As a result, the process produced no other waste streams. In order to demonstrate and evaluate the performance of the SNOX™ process, general operating data were collected and parametric tests conducted to characterize the process and equipment. The system operated for approximately 8,000 hours and produced more than 5,600 tons of commercial-grade sulfuric acid. Many of the tests for the SNOX™ system were conducted at three loads—75, 100, and 110% of design capacity. Environmental Performance Particulate emissions from the process were very low (<1 mg/Nm’) due to the characteristics of the SO, cata- lyst and the sulfuric acid condenser (WSA Condenser). The Niles SNOX™ plant was fitted with a baghouse (rather than an ESP) on its inlet. This was not necessary for low particulate emissions, but rather was needed to maintain an acceptable cleaning frequency for the SO, catalyst. At operating temperature, the SO, catalyst, because of its sticky surface, retained about 90% of the dust that entered the catalyst vessel. Dust that passed through was subsequently removed in the WSA Con- denser, which acted as a condensing particulate removal device (utilizing the dust particulates as nuclei). Minimal or no increase in CO, emissions by the process was tied to two features—the lack of a carbonate- based alkali reagent that releases CO, and the fact that the process recovered additional heat from the flue gas to offset its parasitic energy requirements. This heat recov- ery, under most design conditions, results in the net heat rate of the boiler being the same or better after addition of the SNOX™ process, and consequently no increase in CO, generation per unit of power. With respect to CO and hydrocarbons, the SO, cata- lyst acted to virtually eliminate these compounds as well. This aspect also positively affected the interactiou of the 5-76 Program Update 1999 NO, and SO, catalysts. Because the SO, catalyst fol- lowed the NO, catalyst, any unreacted ammonia (slip) was oxidized in the SO, catalyst to nitrogen, water vapor, and a small amount of NO,. As a result, downstream fouling by ammonia compounds was eliminated and the SCR was operated at slightly higher than typical ammonia stoichiometries. These higher stoichiometries allowed smaller SCR catalyst volumes and permitted the attain- ment of very high reduction efficiencies (>95%). Sulfur dioxide removal in the SNOX™ process was controlled by the efficiency of the SO,-to-SO, oxidation, which occurred as the flue gas passed through the oxida- tion catalyst beds. The efficiency was controlled by two factors—space velocity and bed temperature. Space velocity governed the amount of catalyst necessary at design flue gas flow conditions, and gas and bed tempera- ture had to be high enough to activate the SO, oxidation reaction. During the test program, SO, removal effi- ciency was normally in excess of 95% for inlet concentra- tions averaging about 2,000 ppm. The SCR portion of the SNOX™ process was able to operate at higher than typical ammonia stoichiometries due to its location ahead of the SO, catalyst beds. Normal operating stoichiometries for the SCR system were in the range of 1.02—1.05, and system reduction efficiencies averaged 94% with inlet NO, levels of approximately 500-700 ppm. Sulfuric acid concentration and composition has met or exceeded the requirements of the federal specifications for Class I acid. During the design and construction of the SNOX™ demonstration, arrangements were made with a sulfuric acid supplier to purchase and distribute the acid from the plant. The acid has been sold to the agri- culture industry for production of diammonium phosphate fertilizer and to the steel industry for pickling. Ohio Edison also has used a significant amount in boiler water demineralizer systems throughout its plants. Air toxics testing conducted at the Niles SNOX™ plant measured the following substances: A The bottom portion of the SO, converter catalyst, with the catalyst dust collector hopper mounted on steel rails (center), is shown. + Five major and 16 trace elements including mercury, chromium, cadmium, lead, selenium, arsenic, beryl- lium, and nickel * Acids and corresponding anions (hydrogen chloride, hydrogen fluoride, chloride, fluoride, phosphate, sulfate) + Ammonia and cyanide + Elemental carbon * Radionuclides * Volatile organic compounds Environmental Control Devices * Semi-volatile compounds including polynuclear aro- matic hydrocarbons * Aldehydes Most trace elements were captured in the baghouse along with the particulates. A significant portion of the boron and almost all of the mercury escaped to the stack. But selenium and cadmium, normally a problem, were effectively captured in the acid drain, as were organic compounds. Operational Performance Heat recovery was accomplished by the SNOX™ process. In a commercial configuration, it can be utilized in the thermal cycle of the boiler. The process generated recov- erable heat in several ways. All of the reactions that took place with respect to NO, and SO, removal were exother- mic and increased the temperature of the flue gas. This heat plus fuel-fired support heat added in the high-tem- perature SCR/SO, catalyst loop was recovered in the WSA Condenser cooling air discharge for use in the furnace as combustion air. Because the WSA Condenser lowered the temperature of the flue gas to about 210 °F, compared to approximately 300 °F for a typical power plant, additional thermal energy was recovered along with that from the heats of reaction. Economic Performance The economic evaluation of the SNOX™ process showed a capital cost of approximately $305/kW for a 500-MWe unit firing 3.2% sulfur coal. The levelized incremental cost was 6.1 mills/kWh on a constant dollar basis and 7.8 mills/kWh on a current dollar basis (1995$). The equivalent costs per ton of SO, re- moved were $219/ton (constant 1995$) and $384 (current 1995$). Environmental Control Devices Commercial Applications The SNOX™ technology is applicable to all electric power plants and industrial/institutional boilers firing coal, oil, or gas. The high removal efficiency for NO, and SO, makes the process attractive in many applications. Elimination of additional solid waste (except ash) en- hances the marketability in urban and other areas where solid waste disposal is a significant problem. The host utility, Ohio Edison, is retaining the SNOX™ technology as a permanent part of the pollution control system at Niles Station to help Ohio Edison meet its overall SO,/NO, reduction goals. Commercial SNOX™ plants also are operating in Denmark and Sicily. In Denmark, a 305-MWe plant has operated since August 1991. The boiler at this plant burns coals from various suppliers around the world, including the United States; the coals contain 0.5—3.0% sulfur. The plant in Sicily, operating since March 1991, has a capacity of about 30 MWe and fires petroleum coke. Contacts Paul Yosick, Project Manager, (423) 693-7550 ABB Environmental Systems 1409 Center Port Boulevard Knoxville, TN 37932 (423) 694-5203 (fax) Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, NETL, (412) 386-5991 References * Final Report Volume II: Project Performance and Economics. July 1996. Report No. DE-FC22- 90PC89CSS. Final Report Volume I: Public Design. Report No. DOE/PC/89655-T21. (Available from NTIS as DE96050312.) * A Study of Toxic Emissions from a Coal-Fired Power Plant Utilizing the SNOX™ Innovative Clean Coal Technology Demonstration. Volume 1, Sampling/ Results/Special Topics: Final Report. Report No. DOE/PC/93251-T3-Vol. 1. Battelle Columbus Opera- tions. July 1994. (Available from NTIS as DE94018832.) * A Study of Toxic Emissions from a Coal-Fired Power Plant Utilizing the SNOX™ Innovative Clean Coal Technology Demonstration. Volume 2, Appendices: Final Report. Report No. DOE/PC/93251-T3-Vol. 2. Battelle Columbus Operations. July 1994. (Available from NTIS as DE94018833.) <The SNOX™ demonstration at Ohio Edison’s Niles Station Unit No. 2 achieved SO, removal efficiencies exceeding 95% and NO, reduction effectiveness averaging 94%. Ohio Edison is retaining the SNOX™ technology as part of its environmental control system. Program Update 1999 5-77 Environmental Control Devices Combined SO,/NO, Control Technology SO,-NO,-Rox Box™ Flue Gas Cleanup Demonstration Project Project completed. Participant The Babcock & Wilcox Company Additional Team Members Ohio Edison Company—cofunder and host Ohio Coal Development Office—cofunder Electric Power Research Institute—cofunder Norton Company—cofunder and SCR catalyst supplier 3M Company—cofunder and filter bag supplier Owens Corning Fiberglas Corporation—cofunder and filter bag supplier Location Dilles Bottom, Belmont County, OH (Ohio Edison Company’s R.E. Burger Plant, Unit No. 5) Technology The Babcock & Wilcox Company’s SO.-NO,-Rox Box™ (SNRB™) process Plant Capacity/Production 5-MWe equivalent slipstream from a 156-MWe boiler Coal Bituminous coal blend, 3.7% sulfur average Project Funding Total project cost $13,271,620 100% DOE 6,078,402 46 Participant 7,193,218 54 SO,-NO,-Rox Box and SNRB are trademarks of The Babcock & Wilcox Company. 5-78 Program Update 1999 HOT BAGHOUSE BOILER SORBENT INJECTION DRY WASTE TO DISPOSAL AIR PREHEATER STACK HIGH-TEMPERATURE FILTER BAG ALKALI-RICH ASH ON SURFACE SCR CATALYST Project Objective To achieve greater than 70% SO, removal and 90% or higher reduction in NO, emissions while maintaining particulate emissions below 0.03 Ib/10° Btu. Technology/Project Description The SNRB™ process combines the removal of SO,, NO., . . : : ; . “be simulated. and particulates in one unit—a high-temperature bag- house. SO, removal is accomplished using either cal- cium- or sodium-based sorbent injected into the flue gas. NO, removal is accomplished by injecting ammonia (NH,) to selectively reduce NO, in the presence of a selective catalytic reduction (SCR) catalyst. Particulate removal is accomplished by high-temperature fiber bag filters. The 5-MWe SNRB™ demonstration unit is large enough to demonstrate commercial-scale components while minimizing the demonstration cost. Operation at this scale also permitted cost-effective control of the flue gas temperature, which allowed for evaluation of perfor- mance over a wide range of sorbent injection and bag- house operating temperatures. Thus, several different arrangements for potential commercial installations could Environmental Control Devices Calendar Year 1988 1989 1990 3 4/1 2 3 4 1 2 3 4 1 2 3 1998 9/88 12/89 | Cooperative agreement awarded 12/20/89 Preaward DOE selected project (CCT-II) 9/28/88 Design and Construction Operation | Operation initiated 5/92 Construction completed 12/91 Environmental monitoring plan completed 12/31/91 Operation completed 5/93 Preoperational tests initiated 11/91 Design completed 8/91 Ground breaking/construction started 5/9/91 NEPA process completed (MTF) 9/22/89 Results Summary Environmental SO, removal efficiency of 80% was achieved with commercial-grade lime at a calcium-to-sulfur (Ca/S) molar ratio of 2.0 and temperature of 800-850 °F. SO, removal efficiency of 90% was achieved with sugar hydrated and lignosulfonate hydrated lime at a Ca/S molar ratio of 2.0 and temperature of 800-850 °F. SO, removal efficiency of 80% was achieved with sodium bicarbonate at a sodium-to-sulfur (Na,/S) molar ratio of 1.0 and temperature of 425 °F. SO, emissions were reduced to less than 1.2 Ib/10° Btu with 3-4% sulfur coal with a Ca/S molar ratio as low as 1.5 and Na,/S molar ratio of 1.0. Injection of calcium-based sorbents directly upstream of the baghouse at 825-900 °F resulted in higher over- all SO, removal than injection further upstream at temperatures up to 1,200 °F. Environmental Control Devices * NO, reduction of 90% was achieved with an NH,/NO, molar ratio of 0.9 and temperature of 800-850 °F. + Air toxics removal efficiency was comparable to that of an electrostatic precipitator (ESP), except that hy- drogen fluoride (HF) was reduced by 84% and hydro- gen chloride (HCI) by 95%. Operational * Calcium utilization was 40-45% for SO, removals of 85-90%. * Norton Company’s NC-300 zeolite SCR catalyst showed no appreciable physical degradation or change in catalyst activity over the course of the demonstration. No excessive wear or failures occurred with the filter bags tested: 3M’s Nextel ceramic fiber filter bag and Owens Corning Fiberglas’ S-Glass filter bag. Project completed/final report issued 9/95 Economic * Capital cost in 1994 constant dollars for a 250-MWe retrofit was $233/kW, assuming 3.5% sulfur coal and baseline NO, emissions of 1.2 Ib/10° Btu. Program Update 1999 5-79 Project Summary SNRB™ incorporates two successful technology devel- opment efforts that offer distinct advantages over other control technologies. High-temperature filter bags and circular monolith catalyst developments enabled multiple emission controls in a single component with a low plan- area space requirement. As a postcombustion control system, it is simple to operate. The high-temperature bag provides a clean, high-temperature environment compat- ible with effective SCR operation and a surface for en- hanced SO,/sorbent contact (creates a sorbent cake on the surface). Particulate control, which is receiving increas- ing attention, is typical of the superior performance of- fered by pulsed jet baghouses. Environmental Performance Four different sorbents were tested for SO, capture. Cal- cium-based sorbents included commercial grade hydrated lime, sugar-hydrated lime, and lignosulfonate-hydrated lime. In addition, sodium bicarbonate was tested. The optimal location for injecting the sorbent into the flue gas was immediately upstream of the baghouse. Essentially, the SO, was captured by the sorbent in the form of a filter cake on the filter bags (along with fly ash). With the baghouse operating above 830 °F, injection of commercial-grade hydrated lime at Ca/S molar ratios of 1.8 and above resulted in SO, removals of over 80%. At a Ca/S molar ratio of 2.0, performance of the sugar- hydrated lime and lignosulfonate-hydrated lime increased performance by approximately 8%, for overall removal of approximately 90%. SO, removal of 85-90% was ob- tained with calcium utilization in the of 40-45%. Injec- tion of the calcium-based sorbents directly upstream of the baghouse at 825-900 °F resulted in higher overall SO, removal than injection further upstream at temperatures up to 1,200 °F. SO, removal using sodium bicarbonate was 80% at an Na,/S molar ratio of 1.0 and 98% at an Na,/S molar ratio of 2.0, at a significantly reduced baghouse tempera- 5-80 Program Update 1999 ture of 450-460 °F. SO, emissions while burning a 34% sulfur coal were reduced to less than 1.2 Ib/10° Btu with a Ca/S molar ratio as low as 1.5 and Na,/S molar ratio less than 1.0. To capture NO,, ammonia was injected between the sorbent injection point and the baghouse. The ammonia and NO, reacted to form nitrogen and water in the pres- ence of Norton Company’s NC-300 series zeolite SCR catalyst. With the catalyst being located inside the filter bags, it was well protected from potential particulate erosion or fouling. The sorbent reaction products, unre- A The demonstration baghouse is installed on the back side of the power plant. Workers stand by the catalyst holder tube prior to lifting it into the penthouse. acted lime, and fly ash were collected on the filter bags and thus removed from the flue gas. A NO, emission reduction of 90% was readily achieved with ammonia slip limited to less than 5 ppm. This performance reduced NO, emissions to less than 0.10 Ib/10° Btu. NO, reduction was insensitive to tem- peratures over the catalyst design temperature range of 700-900 °F. Catalyst space velocity (volumetric gas flow/ catalyst volume) had a minimal effect on NO, removal over the range evaluated. Turndown capability for tailoring the degree of NO, reduction by varying the rate of ammonia injection was demonstrated for a range of 50-95% NO, reduction. No appreciable physical degradation or change in the catalyst activity was observed over the duration of the test pro- gram. The degree of oxidation of SO, to SO, over the zeolite catalyst appeared to be less than 0.5%. (SO, oxi- dation is a concern for SCR catalysts containing vana- dium.) Leach potential analysis of the catalyst after completion of the field test showed that the catalyst re- mained nonhazardous for disposal. Particulate emissions were consistently below NSPS standards of 0.03 1b/10° Btu, with an average over 30 baghouse particulate emission measurements of 0.018 1b/10° Btu, which corresponds to a collective effi- ciency of 99.89%. Hydrated lime injection increased the baghouse inlet particulate loading from 5.6 to 16.5 1b/10° Btu. Emissions testing with and without the SCR catalyst installed revealed no apparent differences in collection efficiency. On-line cleaning with a pulse air pressure of 30-40 lb/in? was sufficient for cleaning the bag/catalyst assemblies. Typically, one of five baghouse modules in service was cleaned every 30-150 minutes. A comprehensive air toxics emissions monitoring test was performed at the end of the SNRB™ demonstra- tion test program. The targeted emissions monitored included trace metals, volatile organic compounds, semi- volatile organic compounds, aldehydes, halides, and radionuclides. These species were a subset of the 189 Environmental Control Devices hazardous substances identified in the CAAA. Measure- ments of mercury speciation, dioxins, and furans were unique features of this test program. The emissions con- trol efficiencies achieved for various air toxics by the SNRB™ system were generally comparable to those of the conventional ESP at the power plant. However, the SNRB™ system did reduce HCI by an average of 95% and HF emissions by an average of 84%, whereas the ESP had no effect on these constituents. Operation of the SNRB™ demonstration resulted in the production of approximately 830 tons of fly ash and by-product solids. An evaluation of potential uses for the by-product showed that the material might be used for agricultural liming (if pelletized). Also, the solids poten- tially could be used as a partial cement replacement to lower the cost of concrete. Operational Performance A 3,800-hour durability test of three fabric filters was completed at the Filter Fabric Development Test Facility in Colorado Springs, Colorado in December 1992. No signs of failure were observed. All of the demonstration tests were conducted using the 3M Company Nextel ceramic fiber filter bags or the Owens Corning Fiberglas S-Glass filter bags. No excessive wear or failures oc- curred in over 2,000 hours of elevated temperature opera- tion. Economic Performance For a 250-MWe boiler fired with 3.5% sulfur coal and NO, emissions of 1.2 1b/10° Btu, the projected capital cost of a SNRB™ system is approximately $233/kW (1994$), including various technology and project contin- gency factors. A combination of fabric filter, SCR, and wet scrubber for achieving comparable emissions control has been estimated at $360-400/kW. Variable operating costs are dominated by the cost of the SO, sorbent for a system designed for 85-90% SO, removal. Fixed operat- ing costs primarily consist of system operating labor and projected labor and material for the hot baghouse and ash-handling systems. Environmental Control Devices Commercial Applications Commercialization of the technology is expected to de- velop with an initial larger scale application equivalent to 50- to 100-MWe. The focus of marketing efforts is being tailored to match the specific needs of potential industrial, utility, and independent power producers for both retrofit and new plant construction. SNRB™ is a flexible tech- nology that can be tailored to maximize control of SO,, NO,, or combined emissions to meet current performance requirements while providing flexibility to address future needs. Contacts Dot K. Johnson, (330) 829-7395 McDermott Technologies 1562 Belson Street Alliance, OH 44601 (330) 829-7801 (fax) dot.k. johnson@mcdermott.com Lawrence Saroff, DOE/HQ, (301) 903-9483 James U. Watts, NETL, (412) 386-5991 References * SO-NO -Rox Box™ Flue Gas Cleanup Demonstration Final Report. Report No. DOE/PC/89656-T1. The Babcock & Wilcox Company. September 1995. (Available from NTIS as DE96003839.) + 5 MWe SNRB™ Demonstration Facility: Detailed Design Report. The Babcock & Wilcox Company. November 1992. * Comprehensive Report to Congress on the Clean Coal Technology Program: SO.-NO -Rox Box™ Flue Gas Cleanup Demonstration Project. The Babcock & Wilcox Company. Report No. DOE/FE-0145. U.S. Department of Energy. November 1989. (Available from NTIS as DE90004458.) A Workers lower one of the catalyst holder tubes into a mounting plate in the penthouse of the high-temperature baghouse. Program Update 1999 5-81 Environmental Control Devices Combined SO,/NO, Control Technology Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Project completed. Participant Energy and Environmental Research Corporation Additional Team Members Gas Research Institute—cofunder State of Illinois, Department of Commerce & Community Affairs—cofunder Illinois Power Company—host City Water, Light and Power—host Locations Hennepin, Putnam County, IL (Illinois Power Company’s Hennepin Plant, Unit No. 1) Springfield, Sangamon County, IL (City Water, Light and Power’s Lakeside Station, Unit No. 7) Technology Energy and Environmental Research Corporation’s gas reburning and sorbent injection (GR-SI) process Plant Capacity/Production Hennepin: tangentially-fired 80-MWe (gross), 71-MWe (net) Lakeside: cyclone-fired 40-M We (gross), 33-MWe (net) Coal Illinois bituminous, 3.0% sulfur Project Funding Total project cost $37,588,955 100% DOE 18,747,816 50 Participant 18,841,139 50 PromiSORB is a trademark of Energy and Environmental Research Corporation. 5-82 Program Update 1999 SORBENT FEED SILO | BOILER TT ms BURNOUT OVERFIRE AIR i REBURN RECIRCULATED FLUE GAS BOTTOM ASH ECONOMIZER HUMIDIFICATION WATER | ELECTROSTATIC PRECIPITATOR FAN FLY ASH TO WASTE DISPOSAL Project Objective To demonstrate gas reburning to attain at least 60% NO, reduction along with sorbent injection to capture at least 50% of the SO, on two different boiler configurations— tangentially-fired and cyclone-fired—while burning high- sulfur midwestern coal. Technology/Project Description In this process, 80-85% of the fuel was coal and was supplied to the main combustion zone. The remaining 15-20% of the fuel, provided by natural gas, bypassed the main combustion zone and was injected above the main burners to form a reducing (reburning) zone in which NO, was converted to nitrogen. A calcium compound (sorbent) was injected in the form of dry, fine particulates above the reburning zone in the boiler. Lime (Ca(OH),) was the sorbent tested at both sites. This project demon- strated the GR-SI process on two separate boilers repre- senting two different firing configurations—a tangen- tially-fired, 80-MWe (gross) boiler at Illinois Power Company’s Hennepin Plant in Hennepin, Illinois, and a cyclone-fired, 40-MWe (gross) boiler at City Water, Light and Power’s Lakeside Station in Springfield, Illinois. Illinois bituminous coal containing 3% sulfur was the test coal for both Hennepin and Lakeside. A comprehensive test program was conducted at each of the two sites, operating the equipment over a wide range of boiler conditions. Over 1,500 hours of operation was achieved, enabling a substantial amount of data to be obtained. Intensive measurements were taken to quantify the reductions in NO, and SO, emissions, the impact on boiler equipment and operability, and all fac- tors influencing costs. Environmental Control Devices Calendar Year +e 1986 1988 3 4}/1 2 3 4/1 2 3 4 1 2 3 1994 12 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4) 3 4 7/86 7/87 Preaward A NEPA DOE selected Cooperative process project (CCT-I) | agreement completed, 7/24/86 awarded Hennepin 7/14/87 (MTF) 5/9/88 Design completed, both sites 5/89 Construction started, Hennepin 5/89 NEPA process completed, Lakeside (EA) 6/25/89: Environmental monitoring plan completed, Hennepin 10/15/89 Design and Construction Operation ' Operation initiated, Lakeside 5/93 Operation completed, Hennepin 1/93 Construction completed, Lakeside 5/92 Construction completed, Hennepin 8/91 Operation initiated, Hennepin 1/91 Construction started, Lakeside 6/90 Restoration completed, Lakeside 12/95 Project completed/ final report issued 9/98 Operation completed, Lakeside 10/94 Restoration completed, Hennepin 12/93 Environmental monitoring plan completed, Lakeside 11/15/89 i “*Years omitted Results Summary Environmental * On the tangentially-fired boiler, GR-SI NO, reductions of up to 75% were achieved, and an average 67% reduction was realized at an average gas heat input of 18%. * GR-SI SO, removal efficiency on the tangentially-fired boiler averaged 53% with hydrated lime at a calcium- to-sulfur (Ca/S) molar ratio of 1.75 (corresponding to a sorbent utilization of 24%). * On the cyclone-fired boiler, GR-SI NO, reductions of up to 74% were achieved, and an average 66% reduc- tion was realized at an average gas heat input of 22%. * GR-SI SO, removal efficiency on the cyclone-fired boiler averaged 58% with hydrated lime at a Ca/S molar ratio of 1.8 (corresponding to a sorbent utiliza- tion of 24%). Environmental Control Devices * Particulate emissions were not a problem on either Economic unit undergoing demonstration, but humidification * Capital cost for gas reburning (GR) was approximately had to be introduced at Hennepin to enhance ESP $15/kW plus the gas pipeline cost, if not in place performance. (19968). * Three advanced sorbents tested achieved higher SO, + Operating costs for GR were related to the gas/coal capture efficiencies than the baseline Linwood hy- drated lime. PromiSORB™ A achieved 53% SO, capture efficiency and 31% utilization without GR at a Ca/S molar ratio of 1.75. Under the same condi- tions, ProomiSORB™ B achieved 66% so, reduction and 38% utilization, and high-surface-area hydrated lime achieved 60% SO, reduction and 34% utilization. cost differential and the value of SO, emission allow- ances (because GR replaces some coal with gas, it also reduces SO, emissions). + Capital cost for sorbent injection (SI) was approxi- mately $50/kW. Operating costs for SI were dominated by the cost of sorbent and sorbent/ash disposal costs. SI was esti- Operational mated to be competitive at $300/ton of SO, removed. * Boiler efficiency decreased by approximately 1% as a result of increased moisture formed in combustion from natural gas use. * There was no change in boiler tube wastage, tube metallurgy, or projected boiler life. Program Update 1999 5-83 Project Summary The GR-SI project demonstrated the success of gas re- burning and sorbent injection technologies in reducing NO, and SO, emissions. The process design conducted early in the project combined with the vast amount of data collected during the testing created a database ca- pable of applying the technology to all major coal-firing configurations (tangential-, cyclone-, and wall-fired) on both utility and industrial units. The emissions control and performance can be accurately projected as can the capital and operating costs. Environmental Performance (Hennepin) Operational testing, which included optimization testing and long-term testing, was conducted between January 1991 and January 1993. The GR-SI long-term demon- stration tests were carried out from January 1992 to Octo- ber 1992 to verify the system performance over an ex- tended period. The unit was operated at constant loads and with the system under dispatch operation where load was varied to meet plant power output requirements. With the system under dispatch, the load fluctuated over a wide range from 40-MWe to a maximum load of 75-MWe. Over the long-term demonstration period, the average gross power output was 62-MWe. For long-term demonstration testing, the average NO, reduction was approximately 67%. The average SO, removal efficiency was over 53% at a Ca/S molar ratio of 1.75. (Linwood hydrated lime was used throughout these tests except for a few days when Marblehead lime was used.) CO emissions were below 50 ppm in most cases but were higher during operation at low load. A significant reduction in CO, was also realized. This was due to partial replacement of coal with natural gas having a lower carbon-to-hydrogen ratio. This cofir- ing with 18% natural gas resulted in a theoretical CO, emissions reduction of nearly 8% from the coal-fired baseline level. With flue gas humidification, electrostatic precipitator (ESP) collection efficiencies greater than 99.8% and particulate emissions less than 0.025 Ib/10° Btu 5-84 — Program Update 1999 were measured even with an increase in inlet particulate loading resulting from sorbent injection. These levels were comparable to measured baseline emissions of 0.035 Ib/10° Btu and a collection efficiency greater than 99.5%. Following completion of the long-term tests, three specially prepared sorbents were tested. Two were manu- factured by the participant and contained proprietary additives to increase their reactivity toward SO,, and were referred to as PromiSORB™ A and B. The Illinois State Geological Survey developed the other sorbent—high- surface-area hydrated lime—in which alcohol is used to form a material that gives rise to a much higher surface area than that of conventionally hydrated limes. The SO, capture without GR, at a nominal 1.75 Ca/S molar ratio, was 53% for ProomiSORB™ A, 66% for PromiSORB™ B, 60% for high-surface-area hydrated lime, and 42% for Linwood lime. At a 2.6 Ca/S molar ratio, the ProomiSORB™ B yielded 81% SO, removal efficiency. Environmental Performance (Lakeside) Parametric tests were conducted in three series: GR parametric tests, SI parametric tests, and GR-SI optimiza- tion tests. A total of 100 GR parametric tests were con- ducted at boiler loads of 33-, 25-, and 20-MWe. Gas heat input varied from 5-126%. The GR parametric tests achieved a NO, reduction of approximately 60% at a gas heat input of 22-23%. Additional flow modeling and computer modeling studies indicated that smaller reburn- ing fuel jet nozzles could increase reburning fuel mixing and thus improve the NO, reduction performance. A total of 25 SI parametric tests were conducted to isolate the effects of sorbent on boiler performance and operability. Results showed that SO, reduction levels varied with load because of the effect of temperature on the sulfation reaction. At a Ca/S molar ratio of 2.0, 44% SO, reduction was achieved at full load (33-MWe); 38% SO, reduction was achieved at mid load (25-MWe); and 32% SO, reduction was achieved at low load (20-MWe). A The flexible lime-sorbent distribution lines lead from the sorbent splitter to the top of the cyclone-fired boiler at Lakeside Station. In the GR-SI optimization tests, the two technologies were integrated. Modifications were made to the reburn- ing fuel injection nozzles based on the results of the initial GR parametric tests and flow modeling studies. The total cross-sectional area of the reburning jets was decreased by 32% to increase the reburning jet’s penetra- tion characteristics. The decrease in nozzle diameter increased NO, reduction by an additional 3-5% compared to the initial parametric tests. With GR-SI, total SO, reductions resulted from partial replacement of coal with natural gas and sorbent injection. At a gas heat input of 22% and Ca/S molar ratio of 1.8, average NO, reduction Environmental Control Devices during the long-term testing of GR-SI was 66% and the average SO, reduc- tion was 58%. Operational Performance (Hennepin/Lakeside) Sorbent injection increased the fre- quency of sootblower operation but did not adversely affect boiler effi- ciency or equipment performance. Gas reburning decreased boiler effi- ciency by approximately 1.0% be- cause of the increase in moisture formed with combustion of natural gas. Examination of the boiler before and after testing showed no measur- able change in tube wear or metal- lurgy. Essentially, the scheduled life of the boiler was not compromised. The ESPs adequately accommo- dated the changes in ash loading and resistivity with the presence of sor- bent in the ash. No adverse conditions were found to exist. But as mentioned, humidification was added at Hennepin to achieve acceptable ESP performance with GR-SI. Economic Performance (Hennepin/Lakeside) Capital and operating costs depend largely on site-spe- cific factors, such as gas availability at the site, coal/gas cost differential, SO, removal requirements, and value of SO, allowances. It was estimated that for most installa- tion, a 15% gas heat input will achieve 60% NO, reduc- tion. The capital cost for such a GR installation was estimated at $15/kW for 100-MWe and larger plants plus the cost of the gas pipeline (if required) (1996$). Operat- ing costs were almost entirely related to the differential cost of the gas over the coal as reduced by the value of SO, emission allowances. Environmental Control Devices A The natural gas injector was installed on the corner of Hennepin Station’s tangentially-fired boiler. The capital cost estimate for SI was $50/kW. Operating costs for SI were dominated by the cost of the sorbent and sorbent/ash disposal costs. SI was projected to be cost competitive at $300/ton of SO, removed. Commercial Applications The GR-SI process is a unique com- bination of two separate technolo- gies. The commercial applications for these technologies, both sepa- rately and combined, extend to both utility companies and industry in the United States and abroad. In the United States alone, these two tech- nologies can be applied to more than 900 pre-NSPS utility boilers. The technologies also can be applied to new utility boilers. With NO, and SO, removal exceeding 60% and 50%, respectively, these technologies have the potential to extend the life of a boiler or power plant and also provide a way to use higher sulfur coals. Illinois Power has retained the gas-reburning system and City Water, Light & Power has retained the full tech- nology for commercial use. The project was one of two receiving the Air and Waste Management Association’s 1997 J. Deanne Sensenbaugh Award. Contacts Blair A. Folsom, Sr. V.P., (949) 859-8851, ext. 140 General Electric Energy and Environmental Research Corporation 18 Mason Irvine, CA 92618 Lawrence Saroff, DOE/HQ, (301) 903-9483 Jerry L. Hebb, NETL, (412) 386-6079 References * Enhancing the Use of Coals by Gas Reburning and Sorbent Injection; Volume 1—Program Overview. February 1997. * Enhancing the Use of Coals by Gas Reburning—Sor- bent Injection: Volume 4: Gas Reburning Sorbent Injection at Lakeside Unit 7, City Water, Light and Power, Springfield, Illinois. Final Report. Energy and Environmental Research Corporation. March 1996. Report No. DOE/PC/79796-T48-Vol.4. (Available from NTIS as DE96011869.) + Enhancing the Use of Coals by Gas Reburning—Sor- bent Injection; Long Term Testing Period, September 1, 1991—January 15, 1993. Report No. DOE/PC/ 79796-T40. Energy and Environmental Research Corporation. February 1995. (Available from NTIS as DE95011481.) * Enhancing the Use of Coals by Gas Reburning and Sorbent Injection; Volume 2: Gas Reburning—Sorbent Injection at Hennepin Unit 1, Illinois Power Company. Report No. DOE/PC/79796-T38-Vol. 2. Energy and Environmental Research Corporation. October 1994. (Available from NTIS as DE95009448.) * Enhancing the Use of Coals by Gas Reburning and Sorbent Injection; Volume 3: Gas Reburning—Sorbent Injection at Edwards Unit 1, Central Illinois Light Company. Report No. DOE/PC/79796-T38-Vol. 3. Energy and Environmental Research Corporation. October 1994. (Available from NTIS as DE95009447.) Program Update 1999 5-85 Environmental Control Devices Combined SO,/NO, Control Technology LIMB Demonstration Project Extension and Coolside Demonstration Project completed. Participant McDermott Technology, Inc. (formerly The Babcock & Wilcox Company) Additional Team Members Ohio Coal Development Office—cofunder Consolidation Coal Company—cofunder and technology supplier Ohio Edison Company—host Location Lorain, Lorain County, OH (Ohio Edison’s Edgewater Station, Unit No. 4) Technology The Babcock & Wilcox Company’s (B&W) limestone injection multistage burner (LIMB) system; Babcock & Wilcox DRB-XCL* low-NO, burners Consolidation Coal Company’s Coolside duct injection of lime sorbents Plant Capacity/Production 105-MWe Coal Ohio bituminous, 1.6, 3.0, and 3.8% sulfur Project Funding Total project cost $19,311,033 100% DOE 7,591,655 39 Participant 11,719,378 61 DRB-XCL is a registered trademark of The Babcock & Wilcox Company. TAG is a trademark of the Electric Power Research Institute. 5-86 Program Update 1999 LIMB LIMB SORBENT INJECTION LOW-NO, BURNERS COOLSIDE LIMB/COOLSIDE COOLSIDE SORBENT INJECTION HUMIDIFICATION ELECTROSTATIC PRECIPITATOR WASTE HANDLING AND DISPOSAL Project Objective To demonstrate, with a variety of coals and sorbents, that the LIMB process can achieve up to 50% NO, and SO, reductions and to demonstrate that the Coolside process can achieve SO, removal up to 70%. Technology/Project Description The LIMB process reduces SO, by injecting dry sorbent into the boiler at a point above the burners. The sorbent then travels through the boiler and is removed along with fly ash in an electrostatic precipitator (ESP) or baghouse. Humidification of the flue gas before it enters an ESP is necessary to maintain normal ESP operation and to en- hance SO, removal. Combinations of three bituminous coals (1.6, 3.0, and 3.8% sulfur) and four sorbents were tested. Other variables examined were stoichiometry, humidifier outlet temperature, and injection level in the boiler. In the Coolside process, dry sorbent is injected into the flue gas downstream of the air preheater, followed by flue gas humidification. Humidification enhances ESP performance and SO, absorption. SO, absorption is improved by dissolving sodium hydroxide (NaOH) or sodium carbonate (Na,CO,) in the humidification water. The spent sorbent is collected with the fly ash, as in the LIMB process. Bituminous coal with 3.0% sulfur was used in testing. Babcock & Wilcox DRB-XCL* low-NO, burners, which control NO, through staged combustion, were used in demonstrating both LIMB and Coolside technologies. Environmental Control Devices Calendar Year 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 3 4/1 2 3 4 1 |||2) 3) \/4 123 4 1 2 3 4 12 3 4 1 2 3 4 | i) | | 4 123 4 12 3 4 Aj /2 7/86 6/87 7/89 11/92 Preaward Design and Construction Operation f LIMB operational tests initiated 4/90 Coolside operational tests LIMB operational tests completed 8/91 completed 2/90 Construction completed 9/89 DOE selected project (CCT-l) 7124/86 Ground breaking/ NEPA process construction completed (MTF) started 8/87 6/2/87 Cooperative agreement awarded 6/25/87 Coolside operational tests initiated 7/89 Environmental monitoring plan completed 10/19/88 Project completed/final report issued 11/92 * Coolside SO, removal efficiency was 70% at a Ca/S molar ratio of 2.0, a sodium-to-calcium (Na/Ca) ratio of 0.2, and 20 °F approach-to-saturation temperature Results Summary Environmental LIMB SO, removal efficiencies at a calcium-to-sulfur using commercial hydrated lime and 2.8-3.0% sulfur (Ca/S) molar ratio of 2.0 and minimal humidification coal. across the range of coal sulfur contents were 53-61% for ligno lime, 51-58% for calcitic lime, 45-52% for dolomitic lime, and 22-25% for limestone ground to 80% less than 44 microns (325 mesh). Sorbent recycle tests demonstrated the potential to improve sorbent utilization. Operational Humidification enhanced ESP performance, which enabled opacity levels to be kept well within limits. LIMB SO, removal efficiency increased to 32% using limestone ground to 100% minus 325 mesh and in- creased an additional 57% when ground to 100% less LIMB availability was 95%. Coolside did not undergo than 10 microns. testing of sufficient length to establish availability. LIMB SO, removal efficiencies were enhanced by Humidifier performance indicated that operation in a about 10% when humidification down to 20 °F ap- vertical rather than horizontal mode would be better. proach-to-saturation temperature was used. LIMB, which incorporated Babcock & Wilcox DRB-XCL® low-NO, burners, achieved 40-50% NO, reduction. Environmental Control Devices Economic LIMB capital costs were $31—102/kW for plants ranging from 100- to 500-MWe and coals with 1.5— 3.5% sulfur, with a target SO, reduction of 60% (1992$). Annual levelized costs (15-year) for this range of conditions were $392-791/ton of SO, re- moved. Coolside capital costs were $69-160/kW for plants ranging from 100- to 500-MWe and coals with 1.5— 3.5% sulfur, with a target SO, reduction of 70% (1992$). Annualized levelized costs (15-year) for this range of conditions were $482-943/ton of SO, removed. Program Update 1999 5-87 Project Summary The initial expectation with LIMB technology was that limestone calcined by injection into the furnace would achieve adequate SO, capture. Use of limestone in lieu of the significantly more expensive lime would keep operat- ing costs relatively low. However, the demonstration showed that even with fine grinding of the limestone and deep humidification, performance with limestone was marginal. As a result, a variety of hydrated limes were evaluated in the LIMB configuration, demonstrating enhanced performance. Although LIMB performance was enhanced by applying humidification to the point of approaching adiabatic saturation temperatures, perfor- mance did not rely on this deep humidification. Coolside design was dependent upon deep humidifi- cation to improve sorbent reactivity and use of hydrated lime. Sorbent injection was downstream of the furnace. In addition, sorbent activity was enhanced by dissolving sodium hydroxide (NaOH) or sodium carbonate (Na,CO,) in the humidification water. A Water mist, sprayed into the flue gas, enhanced sulfur capture by the sorbent by approximately 10% in the LIMB process when 20 °F approach-to-saturation was used. 5-88 Program Update 1999 Environmental Performance (LIMB) LIMB tests were conducted over a range of Ca/S molar ratios and humidification conditions while burning Ohio coals with nominal sulfur contents of 1.6, 3.0, and 3.8% by weight. Each of four different Exhibit 5-35 LIMB SO, Removal Efficiencies (Percent) sorbents was injected while burning each of the three different coals. Other variables examined were Nominal Coal Sulfur Content stoichiometry, humidifier outlet temperature, and injection level in the boiler. Exhibit 5-35 summa- rizes SO, removal efficiencies for the range of sor- bents and coals tested. While injecting commercial limestone with 80% of the particles less than 44 microns in size, removal efficiencies of about 22% were obtained at a stoichi- ometry of 2.0 while burning 1.6% sulfur coal. How- ever, removal efficiencies of about 32% were Sorbent 3.8% 3.0% 1.6% Ligno lime 61 63 53 Commercial calcitic lime 58 55 51 Dolomitic lime 52 48 45 Limestone NT 25 22 (80% <44 microns) NT = Not tested Test conditions: injection at 181 ft, Ca/S molar ratio of 2.0, minimal humidification. achieved at a stoichiometry of 2.0 when using a limestone with a smaller particle size (.e., all par- ticles were less than 44 microns). A third limestone with essentially all particles less than 10 microns was used to determine what might be the removal efficiency limit. The removal efficiency for this very fine limestone was approximately 5—7% higher than that obtained at similar conditions for limestone with particles all sized less than 44 microns. During the design phase, it was expected that injec- tion at the 181-foot plant elevation level inside the boiler would permit the introduction of the limestone at close to the optimum furnace temperature of 2,300 °F. Testing confirmed that injection at this level, just above the nose of the boiler, yielded the highest SO, removal. Injection was also performed at the 187-foot level and similar removals were observed. Removal efficiencies while injecting at these levels were about 5% higher than while injecting sorbent at the 191-foot level. Removal efficiencies were enhanced by approxi- mately 10% over the range of stoichiometries tested when humidification down to a 20 °F approach-to-saturation temperature was used. The continued use of the low-NO, burners resulted in an overall average NO, emissions level of 0.43 Ib/10° Btu, which is about a 45% reduction. Operational Performance (LIMB) Long-term test data showed that the LIMB system was available about 95% of the time it was called upon to operate. Even with minimal humidification, ESP perfor- mance was adequately enhanced to keep opacity levels well below the permitted limit. Opacity was generally in the 2-5% range while the limit was 20%. Environmental Performance (Coolside) The Coolside process was tested while burning compli- ance (1.2—1.6% sulfur) and noncompliance (2.8-—3.2% sulfur) coals. Objectives of the full-scale test program were to verify short-term process operability and to de- velop a design performance database to establish process economics for Coolside. Key process variables—Ca/S molar ratio, Na/Ca molar ratio, and approach-to-satura- tion temperatures—were evaluated in short-term (6-8 hour) parametric tests and longer term (1-11 day) process operability tests. Environmental Control Devices Exhibit 5-36 Capital Cost Comparison (1992 $/kW) Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO 100-MWe 150-MWe 15 93 150 413 66 116 312 2.5 95 154 421 71 122 316 3.5 102 160 425 73 127 324 250-MWe 500-MWe 1S 46 96 228 31 69 163 2.5 50 101 235 36 76 169 3.5 54 105 240 40 81 174 Exhibit 5-37 Annual Levelized Cost Comparison (1992 $/Ton of SO, Removed) Coal (%S) LIMB Coolside LSFO LIMB Coolside LSFO 100-MWe 150-MWe 1.5 791 943 1418 653 797 1098 2.5 595 706 895 520 624 692 3.5 525 629 665 461 570 527 250-MWe 500-MWe 1.5 549 704 831 480 589 623 2.5 456 567 539 416 502 411 3.5 419 526 413 392 482 321 The test program demonstrated that the Coolside mercially available hydrated lime. Coolside SO, removal depended on Ca/S molar ratio, Na/Ca molar ratio, approach-to-adiabatic-satu- ration, and the physical properties of the hydrated lime. Sorbent recycle showed significant poten- tial to improve sorbent utilization. The observed SO, removal with recycled sorbent alone was 22% at 0.5 available Ca/S molar ratio and 18 °F approach-to-adiabatic-satu- ration. The observed SO, removal with simultaneous recycle and fresh sorbent feed was 40% at 0.8 fresh Ca/S molar ratio, 0.2 fresh Na/Ca molar ratio, 0.5 available recycle, and 18 °F approach-to- adiabatic-saturation. Operational Performance (Coolside) Floor deposits experienced in the ductwork with the horizontal humidification led designers to consider a vertical unit in a com- mercial configuration. Short-term testing did not permit evaluation of Coolside system availability. Economic Performance (LIMB & Coolside) Economic comparisons were made between LIMB, Coolside, and a wet scrubber with limestone injection and forced oxidation process routinely achieved 70% SO, removal at design conditions of 2.0 Ca/S molar ratio, 0.2 Na/Ca molar ratio, and 20 °F approach-to-saturation temperature using com- Environmental Control Devices (LSFO). Assumptions on performance were SO, removal efficiencies of 60, 70, and 95% for LIMB, Coolside, and LSFO, respectively. The EPRI TAG™ methods were used for the economics, which are summarized in Exhibits 5-36 and 5-37. Commercial Application Both LIMB and Coolside technologies are applicable to most utility and industrial coal-fired units and provide alternatives to conventional wet flue gas desulfurization processes. LIMB and Coolside can be retrofitted with modest capital investment and downtime, and their space requirements are substantially less than for conventional flue gas desulfurization processes. LIMB has been sold to an independent power plant in Canada. Babcock & Wilcox has signed 124 contracts for DLB-XCL* low-NO, burners, representing 2,428 burners for 31,467 MWe of capacity. Contacts Paul Nolan, (330) 860-1074 McDermott Technology, Inc. 20 South Van Buren Avenue P.O. Box 351 Barberton, OH 44203-0351 Lawrence Saroff, DOE/HQ, (301) 903-9483 John C. McDowell, NETL, (412) 386-6175 References * T.R. Goots, M.J. DePero, and P.S. Nolan. LIMB Dem- onstration Project Extension and Coolside Demon- stration: Final Report. Report No. DOE/PC/79798- T27. The Babcock & Wilcox Company. November 1992. (Available from NTIS as DE93005979.) * D.C. McCoy et al. The Edgewater Coolside Process Demonstration: A Topical Report. Report No. DOE/ PC/79798-T26. CONSOL, Inc. February 1992. (Available from NTIS as DE93001722.) Coolside and LIMB: Sorbent Injection Demonstra- tions Nearing Completion. Topical Report No. 2. U.S. Department of Energy and The Babcock & Wil- cox Company. September 1990. Program Update 1999 5-89 Environmental Control Devices Combined SO,/NO, Control Technology Milliken Clean Coal Technology Demonstration Project Project completed. Participant New York State Electric & Gas Corporation Additional Team Members New York State Energy Research and Development Authority—cofunder Empire State Electric Energy Research Corporation— cofunder Consolidation Coal Company—technical consultant Saarberg-H6lter-Umwelttechnik, GmbH (S-H-U)—tech- nology supplier The Stebbins Engineering and Manufacturing Com- pany—technology supplier ABB Air Preheater, Inc_—technology supplier DHR Technologies, Inc. (DHR)—operator of advisor control system Location Lansing, Tompkins County, NY (New York State Electric & Gas Corporation’s Milliken Station, Unit Nos. 1 and 2) Technology Flue gas cleanup using S-H-U formic-acid-enhanced, wet limestone scrubber technology; ABB Combustion Engineering’s Low-NO, Concentric Firing System (LNCFS™) Level III; Stebbins’ tile-lined split-module absorber; ABB Air Preheater’s heat-pipe air preheater; and DHR’s PEOA™ Control System. LNCFS is a trademark of ABB Combustion Engineering, Inc. PEOA is a trademark of DHR Technologies, Inc. 5-90 Program Update 1999 HEAT-PIPE AIR-HEATER SYSTEM HOT UNIT #2 BOILER COOL FLUE GAS OUTLET ASH COLD COMBUSTION CCOFA REBURNING AIR INLET OF MICRONIZED. UNIT #1 COAL COAL BOILER ELECTROSTATIC COMBUSTION AIR OUTLET eet) a Vv ea fy ELECTROSTATIC PRECIPITATOR PRECIPITATOR FLUE GAS OUT OF STACK SPLIT MODULE ABSORBER BELOW STACK LIMESTONE PREPARATION AND HANDLING AIR ASH GYPSUM DEWATERING/ HANDLING COMMERCIAL-GRADE GYPSUM FGD BLOWDOWN TREATMENT & RECYCLE ,COMMERCIAL-GRADE CALCIUM CHLORIDE Plant Capacity/Production 300-M We Coal Pittsburgh, Freeport, and Kittanning Coals; 1.5, 2.9 and 4.0% sulfur, respectively. Project Funding Total project cost $158,607,807 100% DOE 45,000,000 28 Participant 113,607,807 72 Project Objective To demonstrate high sulfur capture efficiency and NO, and particulate control at minimum power requirements, zero waste water discharge, and the production of by- products in lieu of wastes. Technology/Project Description The formic acid enhanced S-H-U process is designed to remove up to 98% SO, at high sorbent utilization rates. The Stebbins tile-lined, split-module reinforced concrete absorber vessel provides superior corrosion and abrasion resistance. Placement below the stack saves space and provides operational flexibility. NO, emissions are con- trolled by LNCFS III™ low-NO, burners and by micron- ized coal reburning. A heat-pipe air preheater is inte- grated to increase boiler efficiency by reducing both air leakage and the air preheater’s flue gas exit temperature. To enhance boiler efficiency and emissions reductions, DHR’s Plant Emission Optimization Advisor (PEOA™) provides state-of-the-art artificial-intelligence-based control of key boiler and plant operating parameters. Environmental Control Devices Calendar Year 1991 1992 1993 3.4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2001 9/91 Preaward 10/92 Design and Construction DOE selected Environmental project (CCT-IV) monitoring 9/12/91 plan completed 12/1/94 Fully integrated operation of Units 1 and 2 initiated 6/95 NEPA process completed Construction completed 6/95 (EA) 8/18/93 Operation I Operation initiated on Unit 2 1/95 Ground breaking/construction started 4/93 Design completed 4/93 Cooperative agreement awarded 10/20/92 [ Project completed/final report issued 10/99* Operation completed 6/98 *Projected date Results Summary Environmental * The maximum SO, removal demonstrated was 98% with all seven recycle pumps operating and using formic acid. The maximum SO, removal without formic acid was 95%. * The difference in SO, removal between the two lime- stone grind sizes tested (90%-325 mesh and 90%-170 mesh) while using low-sulfur coal was an average of 2.6 percentage points. * The SO, removal efficiency was greater than the de- sign efficiency during the high velocity test of the concurrent scrubber section up to a liquid-to-gas ratio (L/G) of 110 gallons per 1,000 actual cubic feet of gas. * The co-current pumps had no measurable effect on pressure drop, whereas the countercurrent pumps significantly increased the scrubber pressure drop. The average effect of each countercurrent header was to increase pressure drop by 0.45 inches water column Environmental Control Devices (WC) in the design flow tests and 0.64 inches WC in the high velocity tests. * At full load, LNCFS™ III lowered NO, emissions to 0.39 Ib/10° Btu (compared to 0.64 Ib/10° Btu for the original burners)—a 39% reduction. * During diagnostic tests, LOI was above 4% at full boiler load. During the validation tests (when overfire air limitations were relaxed), the LOI dropped by 0.7 to 1.7 percentage points, with a minor effect on NO. emissions. Operational * Performance of a modified ESP with wider plate spac- ing and reduced plate area exceeded that of the origi- nal ESPs at lower power consumption. * Boiler efficiency was 88.3-88.5% for LNCFS™ III, compared to a baseline of 89.3-89.6%. Air infiltration was low for both heat pipes. Some unaccounted for air leakage occurred at full load, ranging between 2.0-2.4%. * The flue gas side pressure loss for both heat pipes was less than the design maximum of 3.65 inches WC. The primary side pressure drops for both heat pipes were less than the design maximum of 3.6 inches WC. The secondary air side pressure drops for both heat pipes were less than the design maximum of 5.35 inches WC. Economic * Economic data are not yet available. Program Update 1999 5-91 Project Summary The test plan was developed to cover all of the new tech- nologies used in the project. In addition to the technolo- gies tested, the project demonstrated that existing tech- nologies can be used in conjunction with new processes to produce salable by-products. Supplemental monitoring has provided operation and performance data illustrating the success of these processes under a variety of operating conditions. Generally, each test program was divided into four independent subtests: diagnostic, performance, long- term, and validation. (See Micronized Coal Reburning Demonstration for NO, Control for another CCT Program project at this unit.) Environmental Performance The S-H-U FGD system was tested over a 36-month period. Typical evaluations included SO, removal effi- ciency, power consumption, process economics, load following capability, reagent utilization, by-product qual- ity, and additive effects. Parametric testing included formic acid concentration, L/G ratio, mass transfer, coal sulfur content, and flue gas velocity. The maximum SO, removal demonstrated was 98% with all seven recycle pumps operating and using formic acid, and the maxi- mum SO, removal without formic acid was 95%. The difference in SO, removal between the two limestone grind sizes tested (90%-325 mesh and 90%—170 mesh), while using low-sulfur coal was an average of 2.6 per- centage points as shown in Exhibit 5-38. The SO, re- moval efficiency was greater than the design efficiency during the high velocity test of the cocurrent scrubber section up to a liquid-to-gas ratio of 110. The cocurrent pumps had no measurable effect on pressure drop, whereas the countercurrent pumps significantly increased the scrubber pressure drop. As seen in Exhibit 5-39, the average effect of each countercurrent header was to in- crease pressure drop by 0.45 inches water column (WC) in the design flow tests, and 0.64 inches WC in the high velocity tests. Performance of a modified ESP with wider plate spacing and reduced plate area exceeded that of the original ESPs at lower power consumption. The average particulate matter penetration before the ESP modification was 0.22% and decreased to 0.12% after the modifications. At full boiler load (145-150 MWe) and 3.0— Exhibit 5-38 Effect of Limestone Grind 100 | 90 = sob @ > = 70} 3 me S 60+ mn Cy ‘A 90% - 325 MESH 50 0 ppm— Ag’ (DESIGN - NO FORMIC) FORMIC—” 90% - 170 MESH (DESIGN - FORMIC) 40 1 1 1 1 30 60 90 120 150 180 Total L/G (gal/kacf based on pump design) 3.5% economizer O,, the LNCFS™ III lowered NO, emissions from a baseline 5-92. Program Update 1999 Exhibit 5-39 Pressure Drop vs. Countercurrent Headers High Gas Velocity Scrubber Pressure Drop in W.C. Design Gas Velocity 0 1 2 3 Number of Countercurrent Headers of 0.64 Ib/10° Btu to 0.39 Ib/10° Btu (39% reduction). At 80- to 90-MWe boiler load and 4.3—5.0% economizer O,, the LNCFS™ III lowered NO, emissions from a baseline of 0.58 1b/10° Btu to 0.41 Ib/10° Btu (29% reduction). With LNCFS™ III, LOI was maintained below 4% and CO emissions did not increase. Operational Performance The S-H-U FGD system performance goal of 98% SO, removal efficiency was achieved. Similarly, the objective of producing a marketable gypsum by-product from the FGD system was achieved. The test results indicate that the gypsum produced can be maintained at a purity level ex- ceeding 95% with a chloride level less than 100 ppm. Environmental Control Devices However, the goal of producing a marketable calcium tions with limited space. There have been four commer- chloride solution from the FGD blowdown stream was not _ cial sales of the PEOA™ system. achieved. FGD availability for the test period was 99.9%. The modified ESP has performed better than the original ESP at a lower power use. The total voltage current product (V«I) for ESPs is directly proportional to the total power requirement. The modified ESP required only 75% of the Vel demand of the original ESPs. The modified ESP has a smaller plant footprint with fewer internals and a smaller SCA. Total internal plate area is less than one-half that of the original ESPs, tending to lower capital costs. Contacts Jim Harvilla, Project Manager, (607) 762-8630 New York State Electric & Gas Corporation Corporate Drive - Kirkwood Industrial Park P.O. Box 5224 Binghamton, NY 13902-5224 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 Boiler efficiency was 88.3-88.5% for LNCFS™ III, References compared to a baseline of 89.3-89.6%. The lower effi- e ciency was attributed to higher post-retrofit flue gas O, and higher stack temperatures which accompanied the air heater retrofit. When LNCFS™ III and baseline condi- tions are compared, boiler efficiency with LNCFS™ III was 0).2 percentage points higher than baseline. The heat pipe was tested in accordance with ASME Power Test Code for Air Heaters 4.3. Air infiltration was low for both heat pipes. Unaccounted for air leakage occurred at full load, ranging between 2.0-2.4%. The tests showed that the flue gas side pressure loss for both heat pipes was less than the design maximum of 3.65 inches WC. The primary side pressure drops for both heat pipes were less than the design maximum of 3.6 inches WC. The secondary air side pressure drops for both heat pipes were less than the design maximum of 5.35 inches WC. Economic Performance Economic data is not yet available. Commercial Applications The S-H-U process, Stebbins absorber module, and heat- pipe air preheater are applicable to virtually all power plants. The space-saving design features of the technolo- gies, combined with the production of marketable by- products, offer significant incentives to generating sta- Environmental Control Devices Comprehensive Report to Congress on the Clean Coal Technology Program: Milliken Coal Technology Demonstration Project. New York State Electric & Gas Corporation. Report No. DOE/FE-0265P. U.S. Department of Energy. September 1992. (Available from NTIS as DE93001756.) Harvilla, James ef al. “Milliken Clean Coal Technol- ogy Demonstration Project.” Sixth Clean Coal Tech- nology Conference: Clean Coal for the 21" Century— What Will It Take? Volume II - Technical Papers. CONF-980410— VOL II. April 28-May 1, 1998. Program Update 1999 5-93 Environmental Control Devices Combined SO,/NO, Control Technology Integrated Dry NO/SO, Emissions Control System Project completed. Participant Public Service Company of Colorado Additional Team Members Electric Power Research Institute—cofunder Stone and Webster Engineering Corp.—engineer The Babcock & Wilcox Company—burner developer Fossil Energy Research Corporation—operationaltester Western Research Institute—flyash evaluator Colorado School of Mines—bench-scale engineering researcher and tester NOELL, Inc.—urea-injection system provider Location Denver, Denver County, CO (Public Service Company of Colorado’s Arapahoe Station, Unit No. 4) Technology The Babcock & Wilcox Company’s DRB-XCL” low-NO, burners, in-duct sorbent injection, and furnace (urea) injection Plant Capacity/Production 100-MWe Coal Colorado bituminous, 0.4% sulfur Wyoming subbituminous (short test), 0.35% sulfur Project Funding Total project cost $26,165,306 100% DOE 13,082,653 50 Participant 13,082,653 50 DRB-XCL is a registered trademark of The Babcock & Wilcox Company. 5-94 Program Update 1999 AIR COAL LOW-NO, | | OVERFIRE AIR AIR PREHEAT! INJECTION Project Objective To demonstrate the integration of five technologies to achieve up to 70% reduction in NO, and SO, emissions; more specifically, to assess the integration of a down- fired low-NO, burner with in-furnace urea injection for additional NO, removal and dry sorbent in-duct injection with humidification for SO, removal. Technology/Project Description All of the testing used Babcock & Wilcox’s low-NO, DRB-XCL* down-fired burners with overfire air. These burners control NO, by injecting the coal and the com- bustion air in an oxygen-deficient environment. Addi- tional air was introduced via overfire air ports to complete the combustion process and further enhance NO, re- moval. A urea-based selective noncatalytic reduction (SNCR) system was tested to determine how much addi- tional NO, can be removed from the combustion gas. CALCIUM-BASED SORBENT INJECTION HUMIDIFICATION SODIUM-BASED | SORBENT INJECTION FABRIC FILTER DUST COLLECTOR ASO TO DISPOSAL Two types of dry sorbents were injected into the ductwork downstream of the boiler to reduce SO, emis- sions. Either calcium-based sorbent was injected up- stream of the boiler economizer, or sodium-based sorbent downstream of the air heater. Humidification down- stream of the dry sorbent injection was incorporated to aid SO, capture and lower flue gas temperature and gas flow before entering the fabric filter dust collector. The systems were installed on Public Service Com- pany of Colorado’s Arapahoe Station Unit No. 4, a 100-MWe down-fired, pulverized-coal boiler with roof- mounted burners. Environmental Control Devices Calendar Year : I Preaward DOE selected project (CCT-Ill) 12/19/89 Design initiated 6/90 NEPA process completed (MTF) 9/27/90 Design and Construction 4 Environmental monitoring plan completed 8/5/93 Operation initiated 8/92 Construction completed 8/92 Preoperational tests initiated 6/92 Design completed 3/92 Ground breaking/construction started 5/21/91 Cooperative agreement awarded 3/11/91 1988 1989 1990 1991 1992 1993 1994 1995 1996 1999 2000 3 44 1 2 3 4 1 2 3 4 1 2 3 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 3 4 1 2 12/89 3/91 8/92 2/00 Operation Project completed/ final report issued 2/00* Operation completed 12/96 *Projected date “Years omitted Results Summary Environmental DRB-XCL* burners with minimum overfire air re- duced NO, emissions by more than 63% under steady state conditions. With maximum overfire air (24% of total combustion air), a NO, reduction of 62-69% was achieved across the 50- to 110-MWe load range. The SNCR system, using both stationary and retract- able injection lances in the furnace, provided NO, removal of 30-50% at an ammonia (NH,) slip of 10 ppm, thus increasing performance of the total NO, control system to greater than 80% NO, reduction. SO, removal with dry calcium hydroxide injection into the boiler economizer at approximately 1,000 °F was less than 10%; and with injection into the fabric filter duct, SO, removal was less than 40% at a calcium/ sulfur (Ca/S) molar ratio of 2.0. Environmental Control Devices Sodium bicarbonate injection before the air heater demonstrated a long-term SO, removal of approxi- mately 70% at a normalized stoichiometric ratio (NSR) of 1.0. Sodium sesquicarbonate injection ahead of the fabric filter achieved 70% SO, removal at an NSR of 2.0. NO, emissions were generally higher when using sodium bicarbonate than when using sodium sesquicarbonate. Integrated SNCR and dry sodium-based sorbent injec- tion tests showed reduced NH, and NO, emissions. During four series of air toxics tests, the fabric filter successfully removed nearly all trace metal emissions and 80% of the mercury. Operational Arapahoe Unit No. 4 operated more than 34,000 hours with the combustion modifications in place. Avail- ability factor was over 91%. Ec Control system modifications and additional operator training may be necessary to improve NO, control under load-following conditions. Temperature differential between the top and bottom surfaces of the Advanced Retractable Injection Lances (ARIL) caused the lances to bend downward 12-18 inches. Alternative designs corrected the problem. onomic When used on units burning low sulfur coal, the tech- nology offers SO, and NO, removals comparable to a wet scrubber and SCR, but at a lower cost. Total capital costs for the technology ranges from $125/kW to $281/kW for 300 MWe to 50 MWe plants, respectively. Levelized costs are 12.43—7.03 mills/ kWh or 1746-987 $/ton, respectively. Program Update 1999 5-95 Project Summary The Integrated Dry NO,/SO, Emissions Control System combines five major control technologies to form an integrated system to control both NO, and SO,. The low- NO, combustion system consists of 12 Babcock & Wil- cox DRB-XCL" low-NO, burners installed on the boiler roof. The low-NO, combustion system also incorporates three Babcock & Wilcox dual-zone NO, ports added to each side of the furnace approximately 20 feet below the boiler roof. These ports inject up to 25% of the total combustion air through the furnace sidewalls. Additional NO, control was achieved using the urea- based SNCR system. The SNCR when used with the low-NO, combustion system, allowed the goal of 70% NO, reduction to be reached. Further, the SNCR system was an important part of the integrated system, interacting synergistically with the dry sorbent injection (DSI) system to reduce NO, formation and ammonia slip. Initially, the SNCR was designed and installed to incorporate two levels of injectors with 10 injectors at each level. Levels were determined by temperature profiles that existed with the original combustion system. However, the retrofit low-NO, combustion system re- sulted in a decrease in furnace exit gas temperature by approximately 200 °F, thus moving one injector level out of the temperature regime needed for effective SNCR operation. With only one operational injector level, load- following performance was compromised. In order to achieve the desirable NO, reduction at low loads, two alternatives were explored. The first approach was to substitute ammonia for urea. It was shown that ammonia was more effective than urea at low- loads. An on-line urea-to-ammonia conversion system was installed and resulted in improved low-load perfor- mance, but the improvement was not as large as desired for the lowest load (60 MWe). The second approach was to install injectors in the higher temperature regions of the furnace. This was achieved by installing two NOELL ARIL lances into the furnace through two unused soot- 5-96 Program Update 1999 A Public Service Company of Colorado demonstrated low-NO, burners, in-duct sorbent injection, and SNCR at Arapahoe Station near Denver. blower ports. Each lance was nominally 4 inches in diameter and approximately 20 feet in length with a single row of nine injection nozzles. Each injection nozzle consisted of a fixed air orifice and a replaceable liquid orifice. The ability to change orifices allowed not only for removal and cleaning but adjustment of the injection pattern along the length of the lance in order to compensate for any significant maldistributions of flue gas velocity, temperature, or baseline NO, concentration. One of the key features of the ARIL system was its ability to rotate, thus providing a high degree of flexibility in optimizing SNCR performance. The SO, control system was a direct sorbent injec- tion system that could inject either calcium- or sodium- based reagents into the flue gas upstream of the fabric filter. Sorbent was injected into three locations: (1) air heater exit where the temperature was approximately 260 °F, (2) air heater entrance where the temperature was approximately 600 °F, or (3) the boiler economizer region where the flue gas temperature was approximately 1,000 °F. To improve SO, removal with calcium hydrox- ide, a humidification system capable of achieving 20 °F approach-to-saturation was installed approximately 100 feet ahead of the fabric filter. The system designed by Babcock & Wilcox included 84 I-Jet nozzles that can inject up to 80 gal/min into the flue gas duct work. Environmental Performance The combined DRB-XCL® burner and minimum overfire air reduced NO, emissions by over 63% under steady- state conditions and with carefully supervised operations. Under load-following conditions, NO, emissions were about 10-25% higher. At maximum overfire air (4% of total combustion air), the low-NO, combustion system reduced NO, emissions by 62-69% across the load range (60- to 110-MWe). The results verified that the low-NO, burners were responsible for most of the NO, reduction. The original design of two rows of injector nozzles proved relatively ineffective because one row of injectors was in a region where the flue gas temperature was too low for effective operation. At full load, the original design achieved NO, reduction of 45%. However, the performance decreased significantly as load decreased; at 60-MWe, NO, removal was limited to about 11% with an ammonia slip of 10 ppm. The addition of the retractable lances improved low-load performance of the urea-based SNCR injection system. The ability to follow the tem- perature window by rotating the ARIL lances proved to be an important feature in optimizing performance. As a result, the SNCR system achieved NO, removal in the range of 30-50% (at a NH, slip limited to 10 ppm at the fabric filter inlet), increasing total NO, reduction to greater than 80%, significantly exceeding the goal of 70%. Testing of calcium hydroxide injection at the econo- mizer without humidification resulted in SO, removal in the range of 5—8% at a Ca/S molar ratio of 2.0. Higher SO, removal was achieved with duct injection of calcium hydroxide and humidification, with SO, removals ap- proaching 40% at a Ca/S molar ratio of 2.0 and within 20-30 °F approach-to-saturation. Sodium-based reagents were found to be much more effective than calcium-based sorbents and achieved significantly higher SO, removals during dry injection. Sodium bicarbonate injection be- Environmental Control Devices fore the air heater demonstrated short-time SO, removals of 80%. Long-term reductions of 70% were achieved with an NSR of 1.0. Sodium sesquicarbonate achieved 70% removal at an NSR of 2.0 when injected ahead of the fabric filter. A disadvantage of the sodium-based process was that it converted some existing NO to NO,. Even though 5—10% of the NO, was reduced during the conversion process, the net NO, exiting at the stack was increased. While NO is colorless, small quantities of brown/orange NO, caused a visible plume. A major objective was the demonstration of the integrated performance of the NO, emissions control systems and the SO, removal technologies. The results showed that a synergistic benefit occurred during the simultaneous operation of the SNCR and the sodium DSI system in that the NH, slip from the SNCR process sup- pressed the NO, emissions associated with NO-to-NO, oxidation by dry sodium injection. Operating Performance The Arapahoe Unit No. 4 operated more than 34,000 hours with the combustion modifications in place. The availability factor during the period was over 91%. The operational test objectives were met or exceeded. How- ever, there were operational lessons learned during the demonstration that will be useful in future deployment of the technologies. During the operation of the duct injection of calcium hydroxide and humidification under load-following con- ditions, fabric filter pressure-drop significantly increased. This was caused by the buildup of a hard ash cake on the fabric filter bags that could not be cleaned under normal reverse-air cleaning. The heavy ash cake was caused by the humidification system, but it was not determined whether the problem was due to operation at 30 °F ap- proach-to-saturation temperature or an excursion caused by a rapid decrease in load. The performance of the ARIL lances in NO, removal was good; however, the location created some operational Environmental Control Devices problems. A large differential heating pattern between the top and bottom of the lance caused a significant amount of thermal expansion along the upper surface of the lance. This caused the lance to bend downward ap- proximately 12—18 inches after 30 minutes of exposure. Eventually the lances become permanently bent, thus making insertion and retraction difficult. The problem was partially resolved by adding cooling slots at the end of the lance. An alternative lance design provided by Diamond Power Specialty Company (a division of Bab- cock & Wilcox) was tested and found to have less bend- ing due to evaporative cooling, even though its NO. reduction and NH, slip performance were slightly less than for the ARIL lance. When the SNCR and dry sodium systems were oper- ated concurrently, an NH 5 odor problem was encountered around the ash silo. Reducing the NH, slip set points to the range of 4-5 ppm reduced the ammonia concentration in the fly ash to the 100-200 ppm range, but the odor persisted. It was found that the problem was related to the rapid change in pH due to the presence of sodium in the ash. The rapid development of the high pH level and the attendant release of the ammonia vapor appear to be related to the wetting of the fly ash necessary to minimize fugitive dust emissions during transportation and han- dling. Handling ash in dry transport trucks solved this problem. Economic Performance The technology is an economical method of obtaining SO, and NO, reduction on low sulfur coal units. Total estimated capital costs range from 125 to 281 $/kW for capacities ranging from 300 to 50 MWe. Comparably, wet scrubber and SCR capital costs range from 270 to 474 $/kW for the same unit size ranges. On a levelized cost basis, the demonstrated system costs vary from 12.43-7.03 mills/kWh (1,746-987 $/ton of SO,/NO, removed) compared to wet scrubber and SCR levelized costs of 23.34-12.67 mills/kWh (4,974-2,701 $/ton) based on 0.4% sulfur coal. The integrated system is most efficient on smaller low sulfur coal units. As size and sulfur content increases, the cost advantages decrease. Commercial Applications Either the entire Integrated Dry NO./SO, Emissions Con- trol System or the individual technologies are applicable to most utility and industrial coal-fired units and provide lower capital-cost alternatives to conventional wet flue gas desulfurization processes. They can be retrofitted with modest capital investment and downtime, and their space requirements are substantially less. They can be applied to any unit size but are mostly applicable to the older, small- to mid-size units. Contacts Terry Hunt, Project Manager, (303) 571-7113 Utility Engineering 550 15" Street, Suite 800 Denver, CO 80202-4256 Lawrence Saroff, DOE/HQ, (301) 903-9483 Jerry L. Hebb, NETL, (412) 386-6079 References * Hunt, Terry, e¢ al. “Integrated Dry NO./SO, Emissions Control System: Performance Summary.” Fifth An- nual Clean Coal Technology Conference: Technical Papers. January 1997. * Integrated Dry NO /SO, Emissions Control System Calcium-Based Dry Sorbent Injection: Test Report, April 30-November 2, 1993. Report No. DOE/PC/ 90550-T14. Fossil Energy Research Corporation and Public Service Company of Colorado. December 1994. (Available from NTIS as DE95007932.) Comprehensive Report to Congress on the Clean Coal Technology Program: Integrated Dry NO /SO, Emis- sion Control System. Public Service Company of Colorado. Report No. DOE/FE-0212P. U.S. Depart- ment of Energy. January 1991. (Available from NTIS as DE91008624.) Program Update 1999 5-97 Advanced Electric Power Generation Fluidized-Bed Combustion Advanced Electric Power Generation Program Update 1999 5-99 Advanced Electric Power Generation Fluidized-Bed Combustion McIntosh Unit 4A PCFB Demonstration Project Participant City of Lakeland, Lakeland Electric Additional Team Members Foster Wheeler Corporation—supplier of pressurized circulating fluidized-bed (PCFB) combustor and heat exchanger; engineer Siemens Westinghouse Power Corporation—supplier of hot gas filter, gas turbine, and steam turbine Location Lakeland, Polk County, FL (Lakeland Electric’s McIntosh Power Station, Unit No. 4) Technology Foster Wheeler’s PCFB technology integrated with Siemens Westinghouse’s hot gas particulate filter system (HGPFS) and power generation technologies Plant Capacity/Production 137-MWe (net) Coal Eastern Kentucky and high-ash, high-sulfur bituminous coals Project Funding Total project cost $186,588,000 100% DOE 93,252,864 50 Participant 93,335,136 50 Project Objective To demonstrate Foster Wheeler’s PCFB technology coupled with Siemens Westinghouse’s ceramic candle type HGPFS and power generation technologies, which represent a cost-effective, high-efficiency, low-emissions means of adding generating capacity at greenfield sites or in repowering applications. 5-100 Program Update 1999 PRESSURE SORBENT STORAGE | VU PCFB COMBUSOR | : i 4 i a | COAL Ci L : STORAGE CRUSHER BOTTOM ASH COMPRESSED AIR TO PCFB COMUSTOR | AIR | GAS | TURBINE HOT VITIATED AIR FLY ASH fel EXHAUST] | STEAM — | HEAT RECOVERY fe) STEAMGENERATOR |_| STACK Technology/Project Description The project resulted from a restructuring of the DMEC-1 PCFB Demonstration Project awarded under CCT-III. In the first of the two Lakeland Electric projects, McIntosh Unit No. 4A is being constructed with a PCFB combustor adjacent to the existing Unit No. 3 (see also McIntosh Unit 4B Topped PCFB Demonstration Project). Coal and limestone are mixed and fed into the com- bustion chamber. Combustion takes place at a tempera- ture of approximately 1,560—1,600 °F and a pressure of about 200 psig. The resulting flue gas and fly ash leaving the combustor pass through a cyclone and ceramic candle type HGPFS where the particulates are removed. The hot gas leaving the HGPFS is expanded through a Siemens V64.3 gas turbine. The gas inlet temperature of less than 1,650 °F allows for a simplified turbine shaft and blade- cooling system. The hot gas leaving the gas turbine passes through a heat recovery steam generator (HRSG). Heat recovered from both the combustor and HRSG is used to generate steam to power a reheat steam turbine. Approximately 5—10% of the gross power is derived from the gas turbine, with the steam turbine contributing the balance. The project also includes an atmospheric fluidized- bed unit that can be fired on coal or char from the carbon- izer and will replace the PCFB unit during times of PCFB unavailability, allowing various modes of operation. Advanced Electric Power Generation Calendar Year ” 1991 |** 1996 3 4/1 2 3 4/1 2 3 4 1 2 3 2006 Preaward Site change approved (Lakeland) 10/29/96 Cooperative Agreement . signed 12/19/97 Cooperative Agreement awarded 8/1/91 . start DOE selected project NEPA process started 3/99 (CCT-IIl) 12/19/89 Design and Construction Groundbreaking/ construction started 7/01* NEPA process completed (EIS) 10/00* Design completed 9/00* Operation Operation initiated 7/03* Preoperational tests initiated 7/03* Project completed/ Construction completed 7/03* final report issued 7/05* Operation completed 7/05* Environmental monitoring plan completed 4/03* *Projected date “Years omitted Project Status/Accomplishments On December 19, 1997, a Cooperative Agreement modifi- cation was signed implementing the project restructuring from DMEC-I to the City of Lakeland. The Lakeland City Council gave approval in April 1998 for the 10 year plan of Lakeland Electric (formerly Department of Elec- tric & Water Utilities), which included this project. The project schedule anticipates the start of commercial opera- tion of the PCFB (McIntosh 4A) in 2003. In parallel with the first two years of operation of the PCFB, the design, fabrication, and construction of the topped PCFB technology (McIntosh 4B) will occur, with a planned start of operation in 2005. Negotiations con- tinue between Lakeland and Foster Wheeler on the Engineer-Procure-Construct proposal for the technol- ogy island. The Notice of Intent to prepare an EIS was published in the Federal Register on March 26, 1999. The public scoping meeting was held April 13, 1999, in Lakeland, Florida. Advanced Electric Power Generation Recent efforts focused on testing the HGPFS, which is critical to system performance. Silicon carbide and alumina/mullite candle filters proved effective under conditions simulating those of the demonstra- tion unit. At both 1,550 °F and 1,400 °F, the candle filters performed for over 1,000 hours at design levels without evidence of ash bridging or structural failure. Three new oxide-based candle filters showed promise as well and will undergo further testing because of the potential for reduced cost and operation at higher temperatures. Commercial Applications The project serves to demonstrate the PCFB technology for widespread commercial deployment in post-2000. The project will include the first commercial application of hot gas particulate cleanup and one of the first to use a non-ruggedized gas turbine in a pressurized fluidized-bed application. The combined-cycle PCFB system permits the com- bustion of a wide range of coals, including high-sulfur coals, and would compete with the pressurized bub- bling-bed fluidized-bed system. PCFB can be used to repower or replace conventional power plants. Be- cause of modular construction capability, PCFB gener- ating plants permit utilities to add economical incre- ments of capacity to match load growth or to repower plants using existing coal- and waste-handling equip- Another advantage for re- powering applications is the compactness of the pro- ment and steam turbines. cess due to pressurized operation, which reduces space requirements per unit of energy generated. The projected net heat rate for the system is ap- proximately 9,480 Btu/kWh (HHV), which equates to an efficiency greater than 36%. Environmental attributes include in-situ sulfur removal of 95%, NO, emissions less than 0.3 Ib/10° Btu, and particulate matter dis- charge less than 0.03 Ib/10° Btu. Solid waste will in- crease slightly as compared to conventional systems, but the dry material is readily disposable or potentially usable. Program Update 1999 5-101 Advanced Electric Power Generation Fluidized-Bed Combustion Mcintosh Unit 4B Topped PCFB Demonstration Project Participant City of Lakeland, Lakeland Electric Additional Team Members Foster Wheeler Corporation—supplier of carbonizer; engineer Siemens Westinghouse Power Corporation—supplier of topping combustor and high-temperature filter Location Lakeland, Polk County, FL (Lakeland Electric’s McIntosh Power Station, Unit No. 4) Technology Fully integrated second-generation PCFB technology with the addition of a carbonizer island that includes Siemens Westinghouse’s multi-annular swirl burner (MASB) topping combustor Plant Capacity/Production 103-MWe (net) addition to the 137-MWe (net) McIntosh 4A project Coal Eastern Kentucky and high-ash, high-sulfur bituminous coals Project Funding Total project cost $219,635,546 100% DOE 109,608,507 50 Participant 110,027,039 50 Project Objective To demonstrate topped PCFB technology in a fully com- mercial power generation setting, thereby advancing the technology for future plants that will operate at higher gas turbine inlet temperatures and will be expected to achieve cycle efficiencies in excess of 45%. 5-102 Program Update 1999 SORBENT STORAGE COMPRSSED AIR TO CARBONIZER AND PCFB COMBUSTOR i _HOT FUEL GAS | HGPFS | PRESSURE BAR | uo eie | HOT VESSEL HGPFS CYCLONE ,—— a CYCLONE GEN. y | ei a = | Oo Av | -C- +, MCINTOSH 44” U TOPPING — eI COMBUSTOR COMBUSTOR | stonnGe CRUSHER Pees ig FLY ASH | CHAR —~*_| ‘ CARBONIZER STEAM TURBINE BOTTOM ASH | 7) EXHAUST] | : | = GAS | | ae to 4 HEAT RECOVERY he STEAM GENERATOR i 7 STACK Technology/Project Description The project involves the addition of a carbonizer island to the PCFB demonstrated in the McIntosh 4A project. Dried coal and limestone are fed via a lock hopper system to the carbonizer with part of the gas turbine discharge air. The coal is partially gasified at about 1,750—1,800 °F to produce syngas and char solids streams. The limestone is used to absorb sulfur compounds generated during the mild gasification process. After cooling the syngas to about 1,200 °F, the char and limestone entrained with the syngas are removed by a hot gas particulate filter system (HGPFS). The char and limestone are then transferred to the PCFB combustor for complete carbon combustion and limestone utilization. The hot, cleaned, filtered syngas is then fired in the MASB topping combustor to raise the turbine inlet temperature to approximately 2,350 °F. The gas is expanded through the turbine, cooled in a heat recovery steam generator, and exhausted to the stack. The net impact of the addition of the topping cycle is an increase in both power output and efficiency. The coal and limestone used in McIntosh 4B are the same as those used in McIntosh 4A. The 240-MWe (net) plant is expected to have a heat rate of 8,406 Btu/kWh (40.6% efficiency, HHV). The design SO, capture efficiency rate is 95%. Particulate and NO, emissions are expected to be 0.02 1b/10° Btu and 0.17 Ib/10° Btu, respectively. In the final configuration, the gas turbine will produce 58 MWe and the steam tur- bine will produce 207 MWe, while plant auxiliaries will consume about 25 MWe. Advanced Electric Power Generation Calendar Year +e +e 2003 2005 2 3 4/1 2 3 4)1 2 3 4) 1 2 1994 |** 1996 1999 2000 3 4/1 2 3 4 12 3 4 1 2 3 5/93 ——— Preaward 8/94 i NEPA process started 3/99 ite chi d Fooan Doo Cooperative Agreement signed 1/29/98 Cooperative agreement awarded 7/28/94; effective 8/1/94 DOE selected project (CCT-V) 5/4/93 Design and Construction NEPA process completed (EIS) 10/00* Design initiated 7/03* Ground breaking/construction started 5/04* Design completed 5/04* 7/05 Operation Project completed/ final report issued 7/07* Operation completed 7/07* Operation initiated 7/05* Preoperational tests initiated 7/05* Construction completed 7/05* Environmental monitoring plan completed 4/05* *Projected date “Years omitted Project Status/Accomplishments The project resulted from a restructuring of the Four Riv- ers Energy Modernization Project awarded under the fifth solicitation. The Four Rivers project was to demonstrate the integration of a carbonizer (gasifier) and topping combustor (topping cycle) with the PCFB technology. By using a phased approach, Lakeland Electric will be able to demonstrate both PCFB (McIntosh 4A) and topped PCFB (McIntosh 4B) technologies at one plant site. On January 29, 1998, a Cooperative Agreement modification was signed implementing the project re- structuring from Four Rivers Energy Partners to the City of Lakeland. The Lakeland City Council gave approval in April 1998 for the 10 year plan of Lakeland Electric (formerly Department of Electric & Water Utilities), which included this project. In parallel with the first two years of operation of the PCFB (McIntosh 4A), the design, fabrication, and construction of the topped PCFB technology will take place. Start of operation is planned for late 2005. Negotiations continue between Lakeland and Foster Wheeler on the Engineer-Procure- Construct proposal for the technology island. Advanced Electric Power Generation The Notice of Intent to prepare an EIS was pub- lished in the Federal Register on March 26, 1999. The public scoping meeting was held April 13, 1999, in Lake- land, Florida. Recent efforts focused on testing the HGPFS, which is critical to system performance. Silicon carbide and alumina/mullite candle filters proved effective under con- ditions simulating those of the demonstration unit. At both 1,550 °F and 1,400 °F, the candle filters performed for over 1,000 hours at design levels without evidence of ash bridging or structural failure. Three new oxide-based candle filters showed promise as well. These will undergo further testing because of the potential for reduced cost and operation at higher temperatures. Commercial Applications The commercial version of the topped PCFB technology will have a greenfield net plant efficiency of 45% (which equates to a heat rate approaching 7,500 Btu/kWh, HHYV). In addition to higher plant efficiencies, the plant will (1) have a cost of electricity that is projected to be 20% lower than that of a conventional pulverized-coal- fired plant with flue gas desulfurization, (2) meet emis- sion limits allowed by New Source Performance Standard (NSPS), (3) operate economically on a wide range of coals, and (4) be amenable to shop fabrication. The ben- efits of improved efficiency include reduced cost for fuels and a reduction in CO, emissions. The commercial version of the topped PCFB technol- ogy has other environmental attributes, which include in- situ sulfur retention that can meet 95% removal, NO, emissions that will meet or exceed NSPS, and particulate matter discharge of approximately 0.03 Ib/10° Btu. Al- though the system will generate a slight increase in solid waste compared to conventional systems, the material is a dry, readily disposable, and potentially usable material. Program Update 1999 5-103 Advanced Electric Power Generation Fluidized-Bed Combustion JEA Large-Scale CFB Combustion Demonstration Project Participant JEA (formerly Jacksonville Electric Authority) Additional Team Member Foster Wheeler Energy Corporation—technology supplier Location Jacksonville, Duval County, FL (JEA’s Northside Station, Unit No. 2) Technology Foster Wheeler’s atmospheric circulating fluidized-bed (ACFB) combustor Plant Capacity/Production 297.5-MWe (gross), 265-MWe (net) Coal Eastern bituminous, 0.7% sulfur (design) Project Funding Total project cost $309,096,512 100% DOE 74,733,633 24 Participant 234,362,679 76 Project Objective To demonstrate ACFB at 297.5-MWe gross (265-MWe net) representing a scaleup from previously constructed facilities; to verify expectations of the technology’s eco- nomic, environmental, and technical performance to pro- vide potential users with the data necessary for evaluating a large-scale ACFB as a commercial alternative; to ac- complish greater than 90% SO, removal; and to reduce NO, emissions by 60% when compared with conventional technology. INTREX is a trademark of Foster Wheeler Energy Corp. 5-104 Program Update 1999 FEED WATER H.P. STEAM. CIRCULATING FLUIDIZED-BED BOILER COAL/COKE LIMESTONE i ™ yf \ | SECONDARY AIR — XN xX< \ ss 2 a L.P.STEAM TO BY-PRODUCT STORAGE LIME | SLURRY | PARTICULATE | CONTROL | DEVICE HEATED AIR TO BOILER ECONOMIZER AIR POLISHING v SCRUBBER PARTICULATES wuss TO BY-PRODUCT STORAGE AIR PREHEATER 6) CONDENSER L.P. STEAM L.P. STEAM STEAM TURBINE Technology/Project Description A circulating fluidized-bed combustor, operating at atmo- spheric pressure, will be retrofitted into Unit No. 2 of the Northside Station. Coal or the secondary fuel (petroleum coke), primary air, and a solid sorbent (such as lime- stone), are introduced into the lower part of the combus- tor where initial combustion occurs. As the coal particles decrease in size due to combustion, they are carried higher in the combustor when secondary air is intro- duced. As the coal particles continue to be reduced in size, the coal, along with some of the sorbent, is carried out of the combustor, collected in a cyclone separator, and recycled to the lower portion of the combustor. Primary sulfur capture is achieved by the sorbent in the bed. However, additional SO, capture is achieved through the use of a polishing scrubber to be installed ahead of the particulate control equipment. Steam is generated in tubes placed along the combustor’s walls and superheated in tube bundles placed downstream of the particulate separator to protect against erosion. The system will produce approximately 2 x 10° lb/hr of main steam at about 2,400 psig and 1,005 °F, and 1.73 x 10° lb/hr of reheat steam at 600 psig and 1,005 °F. The steam will be used in an existing 297.5-MWe (name- plate) steam turbine. The heat rate for the retrofit plant is expected to be approximately 9,950 Btu/kWh (34% effi- ciency; HHV). Advanced Electric Power Generation Calendar Year ** +e a +e 1989 1990 1992 3.4/1 2 3 4 1 2 1995 1999 1 £2 3 4 1 2 3 4 1 £2 3 4 1 2 3 4/1 2 3 4/1 2 3 4] 1 2 2003 6/89 Preaward i DOE selected Project resited Project Restructuring project (CCT-I) (York) 6/93 Pre-construction 6/23/89 started NEPA process completed 8/99 (EIS York site) 8/11/95 Project restructured 6/92 Design and Construction NEPA process 5/02 5/04 Operation | Operation initiated 5/02" Construction completed 3/02" Preoperational tests started 7/01* Environmental monitoring plan Project restructured and resited . (Jacksonville) 8/26/97 (Els eee completed 7/01 site) 4/00* Project completed/final report issued 5/04* Cooperative agreement modified 9/29/97 Cooperative agreement awarded 11/30/90 Design completed Operation completed 5/04* *Projected date 41/00" “*Years omitted Project Status/Accomplishments The project was successfully resited to Jacksonville, Florida after York County Energy partners and Metropoli- tan Edison Company terminated activities on the ACFB in September 1996. On August 26, 1997, DOE approved the transfer of the ACFB clean coal project from York, Pennsylvania to Jacksonville, Florida. On September 29, 1997, DOE signed a modified cooperative agreement with JEA to cost-share refurbishment of the first (Unit No. 2) of two units at Northside Generating Station. A Public Scoping Meeting on the Environmental Impact Statement (EIS) was held on December 3, 1997, at the Northside Station. The public hearing on the draft EIS was held on September 30, 1999. The closing date on written public comments was October 15, 1999. The project, currently in design, moves atmospheric fluidized-bed combustion technology to the larger sizes of utility boilers typically considered in capacity additions and replacements. The nominal 300-MWe demonstration unit in the JEA project will be more than double the size of the Nucla unit (110-MWe). Features include an inte- Advanced Electric Power Generation grated recycle heat exchanger (INTREX™) in the fur- nace, steam-cooled cyclones, a parallel pass reheat con- trol, an SO, polishing scrubber, and a fabric filter for particulate control. Expected environmental performance is 0.17 Ib/10° Btu for SO, (98% reduction), 0.11 Ib/10° Btu for NO,, and 0.017 Ib/10° Btu for total particulates (0.013 Ib/10° Btu for PM,,). Commercial Applications ACFB technology has good potential for application in both the industrial and utility sectors, whether for use in repowering existing plants or in new facilities. ACFB is attractive for both baseload and dispatchable power appli- cations because it can be efficiently turned down to 25% of full load. Coal of any sulfur or ash content can be used, and any type or size unit can be repowered. In repowering applications, an existing plant area is used, and coal- and waste-handling equipment as well as steam turbine equip- ment are retained, thereby extending the life of a plant. In its commercial configuration, ACFB technology offers several potential benefits when compared to conven- tional pulverized coal-fired systems: lower capital costs; reduced SO, and NO, emissions at lower costs; higher combustion efficiency; a high degree of fuel flexibility (including use of renewable fuels) and dry, granular solid material that is easily disposed of or potentially salable. Program Update 1999 5-105 Advanced Electric Power Generation Fluidized-Bed Combustion Tidd PFBC Demonstration Project Project completed. Participant The Ohio Power Company Additional Team Members American Electric Power Service Corporation— designer, constructor, and manager The Babcock & Wilcox Company—technology sup- plier Ohio Coal Development Office—cofunder Location Brilliant, Jefferson County, OH (Ohio Power Company’s Tidd Plant, Unit No. 1) Technology The Babcock & Wilcox Company’s pressurized fluid- ized-bed combustion (PFBC) system (under license from ABB Carbon) Plant Capacity/Production 70-MWe (net) Coal Ohio bituminous, 2-4% sulfur Project Funding Total project cost $189,886,339 100% DOE 66,956,993 35 Participant 122,929,346 65 Project Objective To verify expectations of PFBC economic, environmental, and technical performance in a combined-cycle repower- ing application at utility scale; and to accomplish greater than 90% SO, removal and NO, emission level of 0.2 Ib/10° Btu at full load. 5-106 — Program Update 1999 DOLOMITE/ LIMESTONE t COAL —* [ | WATER —> \/ ASH FEED WATER INLET BED ASH CYCLONE ICOMPRESSED ASH COOLER PRESSURIZED —— FLUIDIZED-BED BOILER AIR PRESSURE Baenad ‘a VESSEL COMBUSTION! ! 5 “4 ! TURBINE | 7M cen. CLEAN HOT GAS TURBINE —> FEED WATER | ELECTROSTATIC PRECIPITATOR TO DISPOSAL Technology/Project Description Tidd was the first large-scale operational demonstra- tion of PFBC in the United States. The project repre- sented a 13:1 scaleup from the pilot facility. The boiler, cyclones, bed reinjection vessels, and associated hardware were encapsulated in a pressure vessel 45 feet in diameter and 70 feet high. The facility was designed so that one-seventh of the hot gases pro- duced could be routed to an advanced particulate filter (APF). The Tidd facility is a bubbling fluidized-bed com- bustion process operating at 12 atm (175 psi). Pressur- ized combustion air is supplied by the turbine compressor to fluidize the bed material, which consists of a coal- water fuel paste, coal ash, and a dolomite or limestone sorbent. Dolomite or limestone in the bed reacts with sulfur to form calcium sulfate, a dry, granular bed-ash material, which is easily disposed of or is usable as a by- product. A low bed-temperature of about 1,600 °F limits NO, formation. The hot combustion gases exit the bed vessel with entrained ash particles, 98% of which are removed when the gases pass through cyclones. The cleaned gases are Heat from the gases exiting the turbine, combined with heat then expanded through a 15-MWe gas turbine. from a tube bundle in the fluid bed, generates steam to drive an existing 55-MWe steam turbine. Advanced Electric Power Generation Calendar Year 1986 1988 4/1 2 3 4]1 2 3 t Environmental monitoring plan completed 5/25/88 Groundbreaking ceremony 4/6/88 Construction started 12/9/87 Cooperative agreement awarded 3/20/87 NEPA process completed (MTF) 3/5/87 DOE selected project (CCT-I) 7/24/86 Design and Construction | Operation initiated 3/91 Preoperational tests started 12/90 Construction completed 12/90 Design completed 12/90 Operation | Project completed/ final report issued 12/95 Operation completed 3/95 Results Summary Environmental Sorbent size had the greatest effect on SO, removal efficiency as well as stabilization and heat transfer characteristics of the fluidized-bed. SO, removal efficiency of 90% was achieved at full load with a calcium-to-sulfur (Ca/S) molar ratio of 1.14 and temperature of 1,580 °F. SO, removal efficiency of 95% was achieved at full load with a Ca/S molar ratio of 1.5 and temperature of 1,580 °F. NO, emissions were 0.15—0.33 Ib/10° Btu. CO emissions were less than 0.01 Ib/10° Btu. Particulate emissions were less than 0.02 1b/10° Btu. Advanced Electric Power Generation Operational Combustion efficiency ranged from an average 99.3% at low bed levels to an average 99.5% at mod- erate to full bed levels. Heat rate was 10,280 Btu/kWh (HHV, gross output) (33.2% efficiency) because the unit was small and no attempt was made to optimize heat recovery. An advanced particulate filter (APF), using a silicon carbide candle filter array, achieved 99.99% filtration efficiency on a mass basis. PFBC boiler demonstrated commercial readiness. ASEA Stal GT-35P gas turbine proved capable of operating commercially in a PFBC flue gas environment. Economic The Tidd plant was a relatively small-scale facility, and as such, detailed economics were not prepared as part of this project. A recent cost estimate performed on Japan’s 360-MWe PFBC Karita Plant projected a capital cost of $1,263/kW (19978). Program Update 1999 5-107 Project Summary The Tidd PFBC technology is a bubbling fluidized-bed combustion process operating at 12 atmospheres (175 psi). Fluidized combustion is inherently efficient. A pressurized environment further enhances combustion efficiency, allowing very low temperatures that mitigate thermal NO, generation, flue gas/sorbent reactions that increase sorbent utilization, and flue gas energy that is used to drive a gas turbine. The latter contributed signifi- cantly to system efficiency because of the high efficiency of gas turbines and the availability of gas turbine exhaust heat that can be applied to the steam cycle. A bed design temperature of 1,580 °F was established because it was the maximum allowable temperature at the gas turbine inlet and was well below temperatures for coal ash fusion, thermal NO, formation, and alkali vaporization. Coal crushed to one-quarter inch or less was injected into the combustor as a coal/water paste containing 25% water by weight. Crushed sorbent, either dolomite or limestone, was injected into the fluidized bed via two pneumatic feed lines, supplied from two lock hoppers. The sorbent feed system initially used two injector nozzles but was modified to add two more nozzles to enhance distribution. In 1992, a 10-MWe equivalent APF was installed and commissioned as part of a research and development program and not part of the CCT Program demonstration. This system used ceramic candle filters to clean one- seventh of the exhaust gases from the PFBC system. The hot gas cleanup system unit replaced one of the seven secondary cyclones. The Tidd PFBC demonstration plant accumulated 11,444 hours of coal-fired operations during its 54 months of operation. The unit completed 95 parametric tests, including continuous coal-fired runs of 28, 29, 30, 31, and 45 days. Ohio bituminous coals having sulfur contents of 2-4% were used in the demonstration. 5-108 Program Update 1999 Environmental Performance Testing showed that 90% SO, capture was achievable with a Ca/S molar ratio of 1.14 and that 95% SO, capture was possible with a Ca/S molar ratio of 1.5, provided the size gradation of the sorbent being utilized was optimized. This sulfur retention was achieved at a bed temperature of 1,580 °F and full bed height. Limestone induced deterio- ration of the fluidized-bed, and as a result, testing focused on dolomite. The testing showed that sulfur capture as well as sintering was sensitive to the fineness of the dolo- mite sorbent (Plum Run Greenfield dolomite was the design sorbent). Sintering of fluidized-bed materials, a fusing of the materials rather than effective reaction, had become a serious problem that required operation at bed temperatures below the optimum for effective boiler op- eration. Tests were conducted with sorbent size reduced from minus 6 mesh to a minus 12 mesh. The result with the finer material was a major positive impact on process performance without the expected excessive elutriation of sorbent. The finer material increased the fluidization activity as evidenced by a 10% improvement in heat transfer rate and an approximately 30% increase in sor- bent utilization. In addition, the process was much more stable as indicated by reductions in temperature variations in both the bed and the evaporator tubes. Furthermore, sintering was effectively eliminated. NO, emissions ranged from 0.15—0.33 Ib/10° Btu, but were typically 0.2 Ib/10° Btu during the demonstration. These emissions were inherent to the process, which was operating at approximately 1,580 °F. No NO, control enhancements, such as ammonia injection, were required. Emissions of carbon monoxide and particulates were less than 0.01 and 0.02 1b/10° Btu, respectively. Operational Performance Except for localized erosion of the in-bed tube bundle and the more general erosion of the water walls, the Tidd boiler performed extremely well and was considered a commercially viable design. The in-bed tube bundle experienced no widespread erosion that would require A The PFBC demonstration at the repowered 70-MWe unit at Ohio Power’s Tidd Plant led to significant refinements and understanding of the technology. significant maintenance. While the tube bundle experi- enced little wear, a significant amount of erosion on each of the four water walls was observed. This erosion posed no problem, however, because the area affected is not critical to heat transfer and could be protected by refractory. The prototype gas turbine experienced structural problems and was the leading cause of unit unavailability during the first 3 years of operation. However, design changes instituted over the course of the demonstration proved effective in addressing the problem. The Tidd demonstration showed that a gas turbine could operate in a PFBC flue gas environment. Efficiency of the PFBC combustion process was calculated during testing from the amount of unburned carbon in cyclone and bed ash, together with measure- ments of the amount of carbon monoxide in the flue gas. Combustion efficiencies averaged 99.5% at mod- Advanced Electric Power Generation erate to full bed heights, surpassing the design or expected efficiency of 99.0%. Using data for typical full-load operation, a heat rate of 10,280 Btu/kWh (HHV basis) was calculated. This corresponds to a cycle thermodynamic efficiency of 33.2% at a point where the cycle produced 70-MWe of gross electrical power while burning Pittsburgh No. 8 coal. Because the Tidd plant was a repowering appli- cation at a comparatively small scale, the measured efficiency does not represent what would be expected for a larger utility-scale plant using Tidd technology. Studies conducted under the PFBC Utility Demonstra- tion Project showed that efficiencies of over 40% are likely for a larger utility-scale PFBC plant. In summary, the Tidd project showed that the PFBC system could be applied to electric power generation. Further, the demonstration project led to significant re- finements and understanding of the technology in the areas of turbine design, sorbent utilization, sintering, post- bed combustion, ash removal, and boiler materials. Testing of the APF for over 5,800 hours of coal-fired operation showed that the APF vessel was structurally adequate; the clay-bonded silicon carbide candle filters were structurally adequate unless subjected to side loads from ash bridging or buildup in the vessel; bridging was precluded with larger particulates included in the particu- late matter; and filtration efficiency (mass basis) was 99.99%. Economic Performance The Tidd plant was a relatively small-scale demonstration facility, so detailed economics were not prepared as part of this project. However, a recent cost estimate performed on Japan’s 360-MWe PFBC Karita Plant projected a capital cost of $1,263/kW (1997$). Commercial Applications Combined-cycle PFBC permits use of a wide range of coals, including high-sulfur coals. The compactness of bubbling-bed PFBC technology allows utilities to sig- nificantly increase capacity at existing sites. Compact- Advanced Electric Power Generation ness of the process due to pressurized operation re- duces space requirements per unit of energy generated. PFBC technology appears to be best suited for applica- tions of 50 MWe or larger. Capable of being con- structed modularly, PFBC generating plants permit utilities to add increments of capacity economically to match load growth. Plant life can be extended by re- powering with PFBC using the existing plant area, coal- and waste-handling equipment, and steam turbine equipment. The 360-MWe Karita Plant in Japan, which uses ABB Carbon P800 technology, represents a major move toward commercialization of PFBC bubbling-bed technol- ogy. A second generation P200 PFBC is under construc- tion in Germany. Other PFBC projects are under consid- eration in China, South Korea, the United Kingdom, Italy, and Israel. The Tidd project received Power magazine’s 1991 Powerplant Award. In 1992, the project received the National Energy Resource Organization award for demon- strating energy efficient technology. Contacts Michael J. Mudd, (614) 223-1585 American Electric Power Service Corporation 1 Riverside Plaza Columbus, OH 43215, (614) 223-2499 (fax) George Lynch, DOE/HQ, (301) 903-9434 Donald W. Geiling, NETL, (304) 285-4784 References * Tidd PFBC Hot Gas Cleanup Program Final Report. Report No. DOE/MC/26042-5130. The Ohio Power Company. October 1995. (Available from NTIS as DE96000650.) * Tidd PFBC Demonstration Project Final Report, The Ohio Power Company. August 1995. (Available from Including Fourth Year of Operation. DOE Library/Morgantown, 1-800-432-8330, ext. 4184 as DE96000623.) Tidd PFBC Demonstration Project Final Report, March 1, 1994—March 30, 1995. Report No. DOE/ MC/24132-T8. The Ohio Power Company. August 1995. (Available from NTIS as DE96004973.) Tidd PFBC Demonstration Project—First Three Years of Operation. Report No. DOE/MC/24132- 5037-Vol. | and 2. The Ohio Power Company. April 1995. (Available from NTIS as DE96000559 for Vol. 1 and DE96003781 for vol. 2.) A Coal and sorbent conveyors can be seen just after entering the Tidd plant. Program Update 1999 5-109 Advanced Electric Power Generation Fluidized-Bed Combustion Nucla CFB Demonstration Project Project completed. Participant Tri-State Generation and Transmission Association, Inc. Additional Team Members Foster Wheeler Energy Corporation*—technology supplier Technical Advisory Group (potential users)—cofunder Electric Power Research Institute—technical consultant Location Nucla, Montrose County, CO (Nucla Station) Technology Foster Wheeler’s atmospheric circulating fluidized-bed (ACFB) combustion system Plant Capacity/Production 100-MWe (net) Coal Western bituminous— Salt Creek, 0.5% sulfur, 17% ash Peabody, 0.7% sulfur, 18% ash Dorchester, 1.5% sulfur, 23% ash Project Funding Total project cost $160,049,949 100% DOE 17,130,411 11 Participant 142,919,538 89 *Pyropower Corporation, the original technology developer and supplier, was acquired by Foster Wheeler Energy Corp. 5-110 Program Update 1999 COAL SEONDARY AIR < —S me “AIR [ASH) 7 i. SOLID WASE TO DISPOSAL. ‘COMBUSTOR CHAMBER PARTITION | ATMOSHPERIC CIRCULATING FLUIDIZED-BED BOILER HEAT EXCHANGER FABRIC FILTER “| + TO BOILER FEED WATER STEAM TURBINE Project Objective To demonstrate the feasibility of ACFB technology at utility scale and to evaluate the economic, environmental, and operational performance at that scale. Technology/Project Description Nucla’s circulating fluidized-bed system operates at at- mospheric pressure. In the combustion chamber, a stream of air fluidizes and entrains a bed of coal, coal ash, and sorbent (e.g., limestone). Relatively low combustion temperatures limit NO, formation. Calcium in the sorbent combines with SO, gas to form calcium sulfite and sulfate solids, and solids exit the combustion chamber and flow into a hot cyclone. The cyclone separates the solids from the gases, and the solids are recycled for combustor tem- perature control. Continuous circulation of coal and sorbent improves mixing and extends the contact time of solids and gases, thus promoting high utilization of the coal and high-sulfur-capture efficiency. Heat in the flue gas exiting the hot cyclone is recovered in the economizer. Flue gas passes through a baghouse where particulate matter is removed. Steam generated in the ACFB is used to produce electric power. Three small, coal-fired, stoker-type boilers at Nucla Station were replaced with a new 925,000-Ib/hr ACFB steam generator capable of driving a new 74-MWe turbine generator. Extraction steam from this turbine generator powers three existing turbine gen- erators (12-MWe each). Advanced Electric Power Generation Calendar Year Cooperative agreement awarded 10/3/88 Operation test program initiated 8/88 NEPA process completed (MTF) 4/18/88 Environmental monitoring plan completed 2/27/88 DOE selected project (CCT-I) 10/7/87 1987 1988 1989 1990 1991 “1992 1993 1994 1995 1996 1997 3 4/1 2 3 4/1 2 3 4/1 2 3 1 2 3 4/1 2 3 4)/1 2 3 4/41 2 3 2 3 1 2 3 4) 1 2 10/87 10/88 4/92 Preaward Operation i final i Operation Project completed/final report issued 4/92 completed 1/91 Results Summary Environmental Bed temperature had the greatest effect on pollutant emissions and boiler efficiency. At bed temperatures below 1,620 °F, sulfur capture efficiencies of 70 and 95% were achieved at calcium- to-sulfur (Ca/S) molar ratios of 1.5 and 4.0, respectively. During all tests, NO, emissions averaged 0.18 Ib/10° Btu and did not exceed 0.34 Ib/10° Btu. CO emissions ranged from 70-140 ppmv. Particulate emissions ranged from 0.0072-0.0125 Ib/10° Btu, corresponding to a removal efficiency of 99.9%, Solid waste was essentially benign and showed poten- tial as an agricultural soil amendment, soil/roadbed stabilizer, or landfill cap. Advanced Electric Power Generation Operational Boiler efficiency ranged from 85.6—88.6% and com- bustion efficiency ranged from 96.9-98.9%. A 3:1 boiler turndown capability was demonstrated. Heat rate at full load was 11,600 Btu/kWh and was 12,400 Btu/kWh at half load. Economic Capital cost for the Nucla retrofit was $1,123/kW and a normalized power production cost was 64 mills/kWh. Program Update 1999 5-111 Project Summary Fluidized-bed combustion evolved from efforts to find a combustion process conducive to controlling pollutant emissions without external controls. Fluidized-bed com- bustion enables efficient combustion at temperatures of 1,400-1,700 °F, well below the thermal NO, formation temperature (2,500 °F), and enables high SO,-capture efficiency through effective sorbent/flue gas contact. ACEB differs from the more traditional fluid-bed combus- tion. Rather than submerging a heat exchanger in the fluid bed, which dictates a low-fluidization velocity, ACFB uses a relatively high fluidization velocity, which entrains the bed material. Hot cyclones capture and return the solids emerging from the turbulent bed to control temperature and extend the gas/solid contact time and to protect a downstream heat exchanger. Interest and participation of DOE, EPRI, and the Technical Advisory Group (potential users) resulted in the evaluation of ACFB potential for broad utility application through a comprehensive test program. Over a two-and-a- half-year period, 72 steady-state performance tests were conducted and 15,700 hours logged. The result was a database that remains the most comprehensive, available resource on ACFB technology. Operational Performance Between July 1988 and January 1991, the plant operated with an average availability of 58% and an average capac- ity factor of 40%. However, toward the end of the demon- stration, most of the technical problems had been over- come. During the last three months of the demonstration, average availability was 97% and the capacity factor was 66.5%. Over the range of operating temperature at which testing was performed, bed temperature was found to be the most influential operating parameter. With the excep- tion of coal-fired configuration and excess air at elevated temperatures, bed temperature was the only parameter that had a measurable impact on emissions and effi- ciency. 5-112 Program Update 1999 V Plant layout with coal and limestone feed locations. boy oF Front Wall Front Wall > eu Combustor comer| Beton Ash Combustor Botti O jottom i i hak Side Center] | Side cose) Wall Wall | | Wall Wall Owe Rear Wall Rear Wall f= > i ? « | + Loop Seals - - } Economizer oan N j——> Coal Feed Point |ts***#*> Limestone Feed Point Exhibit 5-40 Effect of Bed Temperature on Ca/S Requirement 65 T 6.0 + + 5.5 { 5.0 ' | : I 1 45 t | t 4 4.0. 3.5) } | | ee : 23 | 2.0} 1500 1550 1600 1650 Mean Bed Temperature (_ F) Ca/S Molar Ratio 1s. 5 10. 1450 1700 1750 Combustion efficiency, a measure of the quantity of carbon that is fully oxidized to CO,, ranged from 96.9-98.9%. Of the four exit sources of incompletely burned carbon, the largest was carbon contained in the fly ash (93%). The next largest (5%) was carbon contained in the bottom ash stream, and the remaining feed-carbon loss (2%) was incompletely oxidized CO in the flue gas. The fourth possible source, hydrocarbons in the flue gas, was measured and found to be negligible. Boiler efficiencies for 68 performance tests varied from 85.6-88.6%. The contributions to boiler heat loss were identified as unburned carbon, sensible heat in dry flue gas, fuel and sorbent moisture, latent heat in burning hydrogen, sorbent calcination, radiation and convection, and bottom-ash cooling water. Net plant heat rate de- creased with increasing boiler load, from 12,400 Btu/kWh at 50% of full load to 11,600 Btu/kWh at full load. The lowest value achieved during a full-load steady-state test was 10,980 Btu/kWh. These values were affected by the absence of reheat, the presence of the three older 12.5- MWe turbines in the overall steam cycle, the number of unit restarts, and part-load testing. Environmental Performance As indicated above, bed temperature had the greatest impact on ACFB performance, including pollutant emis- sions. Exhibit 5-40 shows the effect of bed temperatures on the Ca/S molar ratio requirement for 70% sulfur reten- tion. The Ca/S molar ratios were calculated based on the calcium content of the sorbent only, and do not account for the calcium content of the coal. While a Ca/S molar ratio of about 1.5 was sufficient to achieve 70% sulfur retention in the 1,500—1,620 °F range, the Ca/S molar ratio requirement jumped to 5.0 or more at 1,700 °F or greater. Exhibit 5-41 shows the effect of Ca/S molar ratio on sulfur retention at average bed temperatures below 1,620 °F. Salt Creek and Peabody coals contain 0.5% and 0.7% sulfur, respectively. To achieve 70% SO, reduc- Advanced Electric Power Generation Exhibit 5-41 Calcium Requirements and Sulfur Retentions for Various Fuels crease as temperature increases, from 140 ppmv at 1,425 °F to 70 ppmv at 1,700 °F. At full load, the hot cyclones removed 99.8% of the particulates. With the addition of baghouses, removal efficiencies achieved on Peabody and Salt Creek Coals Sulfur Retention (%) S$ — Correlation | © Dorchester @ = Salt Creek ™ Peabody were 99.905% and 99.959%, respectively. This equated to emission levels of 0.0125 Ib/10° Btu for Peabody coal and 0.0072 Ib/ 10° Btu for Salt Creek coal, well below the required 0.03 Ib/10° Btu. Economic Performance The final capital costs associated with the engineering, construction, and startup of the Nucla ACFB system were $112.3 million. 0 1 2 3 4 5 Ca/S Ratio 6 This represents a cost of $1,123/kW (net). Total power costs associated with plant tion, or the 0.4 Ib/10° Btu emission rate required by the licensing agreement, a Ca/S molar ratio of approxi- mately 1.5 is required. To achieve an SO, reduction of 95%, a Ca/S molar ratio of approximately 4.0 is neces- sary. Dorchester coal, averaging 1.5% sulfur content, required a somewhat lower Ca/S molar ratio for a given reduction. NO, emissions measured throughout the demonstra- tion were less than 0.34 Ib/10° Btu, which is well below the regulated value of 0.5 Ib/10° Btu. The average level of NO, emissions for all tests was 0.18 1b/10° Btu. NO, emissions indicate a relatively strong correlation with temperature, increasing from 40 ppmv (0.06 Ib/10° Btu) at 1,425 °F to 240 ppmv (0.34 Ib/10° Btu) at 1,700 °F. Limestone feed rate was also identified as a variable affecting NO, emissions, i.e., somewhat higher NO, emissions resulted from increasing calcium-to-nitrogen (Ca/N) molar ratios. The mechanism was believed to be oxidation of volatile nitrogen in the form of ammonia (NH,) catalyzed by calcium oxide. CO emissions de- Advanced Electric Power Generation operations between September 1988 and January 1991 were approximately $54.7 million, resulting in a normalized cost of power produc- tion of 64 mills/kWh. The average monthly operating cost over this period was about $1,888,000. Fixed costs represent about 62% of the total and include interest (47%), taxes (4.8%), depreciation (6.9%), and insurance (2.7%). Variable costs represent more than 38% of the power production costs and include fuel expenses (26.2%), non-fuel expenses (6.8%), and maintenance expenses (5.5%). Commercial Applications The Nucla project represented the first repowering of a U.S. utility plant with ACFB technology and showed the technology’s effectiveness to burn a wide variety of coals cleanly and efficiently. The comprehensive database resulting from the Nucla project enabled the resultant technology to be replicated in numerous commercial plants throughout the world. Nucla contin- ues in commercial service. Today, every major boiler manufacturer offers an ACFB system in its product line. There are now more than 120 fluidized-bed combustion boilers of varying capacity operating in the U.S. and the technology has made significant market penetration abroad. The fuel flexibility and ease of operation make it a particularly attractive power generation option for the burgeoning power market in developing countries. Contacts Stuart Bush, (303) 452-6111 Tri-State Generation and Transmission Ass’n., Inc. P.O. Box 33695 Denver, CO 80233 George Lynch, DOE/HQ, (301) 903-9434 Thomas Sarkus, NETL, (412) 386-5981 References * Colorado-Ute Nucla Station Circulating Fluidized- Bed (CFB) Demonstration—Volume 2: Test Program Results. EPRI Report No. GS-7483. October 1991. * Demonstration Program Performance Test: Summary Reports. Report No. DOE/MC/25137-3104. Colorado- Ute Electric Association, Inc. March 1992. (Available from NTIS as DE92001299.) * Economic Evaluation Report: Topical Report. Report No. DOE/MC/25137-3127. Colorado-Ute Electric Association, Inc., March 1992. (Available from NTIS as DE93000212.) * Nucla CFB Demonstration Project: Detailed Pub- lic Design Report. Report No. DOE/MC/25137-2999. Colorado-Ute Electric Association, Inc., December 1990. (Available from NTIS as DE91002081.) Program Update 1999 5-113 Advanced Electric Power Generation Integrated Gasification Combined-Cycle dvanced Electric Power Generation Program Update 1999 5-115 Advanced Electric Power Generation Integrated Gasification Combined Cycle Kentucky Pioneer Energy IGCC Demonstration Project Participant Kentucky Pioneer Energy, L.L.C. Additional Team Members Fuel Cell Energy, Inc. (formerly Energy Research Corpora- tion)—molten carbonate fuel cell designer and sup- plier; cofunder Location Trapp, Clark County, KY (East Kentucky Power Cooperative’s Smith site) Technology Integrated gasification combined-cycle (IGCC) using a BGL (formerly British Gas/Lurgi) slagging fixed-bed gasification system coupled with Energy Research Corporation’s molten carbonate fuel cell (MCFC) Plant Capacity/Production 400-MWe (net) IGCC; 2.0-MWe MCFC Coal High-sulfur Kentucky bituminous coal blended with mu- nicipal solid waste Project Funding Total project cost $431,932,714 100% DOE 78,086,357 18 Participant 353,846,225 82 Project Objective To demonstrate and assess the reliability, availability, and maintainability of a utility-scale IGCC system using a high-sulfur bituminous coal and municipal solid waste blend in an oxygen-blown, fixed-bed, slagging gasifier and the operability of a molten carbonate fuel cell fueled by coal gas. 5-116 Program Update 1999 STEAM AND ARTICULATES OXYGEN rate LIQUOR TO DISPOSAL 3 1s AQUEOUS EFFLUENT sag CONVENTIONAL BRITISH GAS LURGI COAL AND COAL —— BRIQUETTES GASIFIER OXYGEN |) : Il PLANT i —o7, (qe. ) PRODUCT : GAS are : COOLER COMBUSTOR TARS, OILS RATE : 8 PARTICULATES GAS-POLISHING AND MOISTURIZATION GAS CLEANUP FUEL CELL —_ || GAS TURBINE |HOT GAS }| | + EXHAUST. HEAT RECOVERY |GAS |_ SULFUR 7 steam ==> RECOVERY | | | STEAM \. GENERATOR ef STACK | ot I A iz |} —_— + b> 5 GEN SULFUR | BY-PRODUCT ) STEAM TURBINE Technology/Project Description The BGL gasifier is supplied with steam, oxygen, lime- stone flux, and a coal and municipal waste blend. During gasification, the oxygen and steam react with the coal and limestone flux to produce a raw, coal-derived fuel gas rich in hydrogen and carbon monoxide. Raw fuel gas exiting the gasifier is washed and cooled. Hydrogen sulfide and other sulfur compounds are removed. Elemental sulfur is reclaimed and sold as a by-product. Tars, oils, and dust are recycled to the gasifier. The resulting clean, medium- Btu fuel gas fires a gas turbine. A small portion of the clean fuel gas is used for the MCFC. The MCFC is composed of a molten carbonate elec- trolyte sandwiched between porous anode and cathode plates. Fuel (desulfurized, heated medium-Btu fuel gas) and steam are fed continuously into the anode; CO,-enriched air is fed into the cathode. Chemical reactions produce direct electric current, which is con- verted to alternating power in an inverter. Advanced Electric Power Generation Calendar Year +e 1992 3 4/1 2 3 4/1 2 3 4;/1 2 8 1 2 3 4/1 2 3 4/1 2 3 4/41 2002 2 2003 2004 2005 3°4/1 2 3 4 1 2 3 4 1 2 | Preaward Cooperative Agreement awarded 12/2/94 DOE selected project New site approved 5/98 (CCT-V) 5/4/93 Design and Construction Start construction 2/01* Novation of cooperative agreement; New site approved 11/99* 7/03 7104 Operation | Operation initiated 7/03* Final report issued/project completed 7/04* *Projected date “Years omitted Project Status/Accomplishments On May 8, 1998, the DOE conditionally approved Ameren Services Company (merger of Union Electric Co. and Central Illinois Public Service Co.) as an equity part- ner and host site provider subject to completing specific business and teaming milestones. The new project site to be provided by Ameren was at their Venice Station Plant in Venice, Illinois, or near East St. Louis, Illinois. On April 30, 1999, Ameren Services Company withdrew from the project for economic and business reasons. In May 1999, Global Energy USA Limited (Global), sole owner of Kentucky Pioneer Energy L.L.C. (KPE), expressed interest in acquiring the project and providing a host site at East Kentucky Power Cooperative’s Smith Site in Clark County, Kentucky. Subsequently, Global negotiated all the necessary documents with DOE and Clean Energy Partners, L.P. (CEP) to acquire the project. Advanced Electric Power Generation Commercial Applications The IGCC system being demonstrated in this project is suitable for both repowering applications and new power plants. The technology is expected to be adaptable to a wide variety of potential market applications because of several factors. First, the BGL gasification technology has successfully used a wide variety of U.S. coals. Also, the highly modular approach to system design makes the BGL-based IGCC and molten carbonate fuel cell competi- tive in a wide range of plant sizes. In addition, the high efficiency and excellent environmental performance of the system are competitive with or superior to other fossil- fuel-fired power generation technologies. The heat rate of the IGCC demonstration facility is projected to be 8,560 Btu/kWh (40% efficiency) and the commercial embodiment of the system has a projected heat rate of 8,035 Btu/kWh (42.5% efficiency). The com- mercial version of the molten carbonate fuel cell fueled by a BGL gasifier is anticipated to have a heat rate of 7,379 Btu/kWh (46.2% efficiency). These efficiencies represent a greater than 20% reduction in emissions of CO, when compared to a conventional pulverized coal plant equipped with a scrubber. SO, emissions from the IGCC system are expected to be less than 0.1 Ib/10° Btu (99% reduction); and NO, emissions less than 0.15 1b/10° Btu (90% reduction). Also, the slagging characteristic of the gasifier pro- duces a nonleaching, glass-like slag that can be marketed as a usable by-product. Program Update 1999 5-117 Advanced Electric Power Generation Integrated Gasification Combined Cycle Pinon Pine IGCC Power Project Participant Sierra Pacific Power Company Additional Team Members Foster Wheeler USA Corporation—architect, engineer, and constructor The M.W. Kellogg Company—technology supplier Bechtel Corporation—start-up engineer Location Reno, Storey County, NV (Sierra Pacific Power Company’s Tracy Station) Technology Integrated gasification combined-cycle (IGCC) using the KRW air-blown pressurized fluidized-bed coal gasification system Plant Capacity/Production 107-MWe (gross), 99-MWe (net) Coal Southern Utah bituminous, 0.5—0.9% sulfur (design coal); eastern bituminous, 2—3% sulfur (planned test) Project Funding Total project cost $335,913,000 100% DOE 167,956,500 50 Participant 167,956,500 50 Project Objective To demonstrate air-blown pressurized fluidized-bed IGCC technology incorporating hot gas cleanup; to evaluate a low-Btu gas combustion turbine; and to assess long-term reliability, availability, maintainability, and environmental performance at a scale sufficient to determine commercial potential. 5-118 — Program Update 1999 FLUIDIZED-BED GASIFIER CYCLONE COAL & LIMESTONE HANDLING SOLID WASTE AGGLOMERATES GAS COOLER STEAM TO HRSG fi ") CLEANUP | SULFUR REMOVAL | GEN. COMBUSTION TURBINE | 1o7 Gas ’ STEAM FROM GAS COOLER, STEAM TURBINE Technology/Project Description Dried and crushed coal and limestone are introduced into a KRW air-blown pressurized fluidized-bed gasifier. Crushed limestone is used to capture a portion of the sulfur. The sulfur reacts with the limestone to form cal- cium sulfide which, after oxidation, exits as calcium sulfate along with the coal ash in the form of agglomer- ated particles suitable for landfill. Low-Btu coal gas leaving the gasifier passes through cyclones, which return most of the entrained particulate matter to the gasifier. The gas, which leaves the gasifier at about 1,700 °F, is cooled to about 1,100 °F before entering the hot gas cleanup system. During cleanup, virtually all of the remaining particulates are removed by ceramic candle filters, and final traces of sulfur are removed by reaction with a metal oxide sorbent in a transport reactor. The cleaned gas then enters the GE MS6001FA (Frame 6FA) combustion turbine, which is coupled to a 61-MWe (gross) generator. Exhaust gas from the com- bustion turbine is used to produce steam in an HRSG. Superheated high-pressure steam drives a condensing steam turbine-generator designed to produce about 46 MWe (gross). The IGCC plant will remove 95+% of the sulfur in the coal. Due to the relatively low operating temperature of the gasifier and the injection of steam into the combus- tion fuel stream, the NO, emissions are expected to be 70% less than a conventional coal-fired plant. The IGCC will produce 20% less CO, than conventional plants. Advanced Electric Power Generation Calendar Year 1991 3 4/1 2 3 4/1 2 3 4/1 2 3 1996 9/91 8/92 Preaward | DOE selected project (CCT-IV) 9/12/91 Cooperative agreement awarded 8/1/92 Design and Construction Operation Operation initiated 1/98 Construction completed 2/97 11/96 Preoperational tests initiated Environmental monitoring plan completed 10/31/96 Design completed 8/95 Ground breaking/construction started 2/95 NEPA process completed (EIS) 11/8/94 1/01* 1/01* Project completed/final report issued Operation completed *Projected date Project Status/Accomplishments The system has initiated test-plan operations but contin- ues to experience operational difficulties. The station began operation on natural gas in November 1996. Pre- operational testing and shakedown of the coal gasification combined-cycle system continued through 1997 with syngas produced in January 1998. The plant was dedi- cated in April 1998. The project continues to suffer from a number of design issues, many of which have been solved, but others remain. In 1998 and the first three months of 1999, the gasifier had 10 successful runs, which averaged 7 hours each, with the longest being 12 hours. The gasifier has produced syngas for over 33 hours. Problems have been attributed to the high degree of new technology, high scaleup factors on auxiliary components, and some design and engineering deficiencies. Nevertheless, Sierra Pacific is confident that no fatal flaws exist that will preclude successful demonstration and subsequent commercializa- tion of the KRW gasification technology. Advanced Electric Power Generation Despite the problems with the gasifier, the plant continues to operate on natural gas. The first-of-a-kind GE Frame 6FA CT had an 85 percent availability in 1998 and a 100 percent availability in the first quarter of 1999. Sierra Pacific’s 2000 performance goals include: 90 per- cent combined-cycle availability; achieve stable, sustained production of syngas; demonstrate sustained operation on syngas; and successfully run the gas turbine on syngas. Commercial Applications The Pifion Pine IGCC system concept is suitable for new power generation, repowering needs, and cogeneration applications. The net heat rate for a proposed greenfield plant using this technology is projected to be 7,800 Btu/ kWh (43.7% efficiency), representing a 20% increase in thermal efficiency compared to a conventional pulverized coal plant with a scrubber and a comparable reduction in CO, emissions. The compactness of an IGCC system reduces space requirements per unit of energy generated relative to other coal-based power generation systems. The advantages provided by phased modular construction reduce the financial risk associated with new capacity additions. The KRW IGCC technology is capable of gasifying all types of coals, including high-sulfur, high-ash, low- rank, and high-swelling coals, as well as bio- or refuse- derived waste, with minimal environmental impact. There are no significant process waste streams that re- quire remediation. The only solid waste from the plant is a mixture of ash and calcium sulfate, a nonhazardous waste. Program Update 1999 5-119 Advanced Electric Power Generation Integrated Gasification Combined Cycle Tampa Electric Integrated Gasification Combined-Cycle Project Participant Tampa Electric Company Additional Team Members Texaco Development Corporation—gasification technology supplier General Electric Corporation—combined-cycle technology supplier Air Products and Chemicals, Inc.—air separation unit supplier Monsanto Enviro-Chem Systems, Inc.—sulfuric acid plant supplier TECO Power Services Corporation—project manager and marketer Bechtel Power Corporation—architect and engineer Location Mulberry, Polk County, FL (Tampa Electric Company’s Polk Power Station, Unit No. 1) Technology Advanced integrated gasification combined-cycle (IGCC) system using Texaco’s pressurized, oxygen-blown en- trained-flow gasifier technology Plant Capacity/Production Output: 316 MWe (gross), 250 MWe (net) Coal Illinois #6, Pittsburgh #8, Kentucky # 11, and Kentucky #9; 2.5-3.5% sulfur Project Funding Total project cost $303,288,446 100% DOE 150,894,223 49 Participant 152,394,223 51 5-120 Program Update 1999 - - Future SLURRY ENTRAINED- 7 PLANT FLOW GASIFIER ee aw [1 COAL : SYNGAS | SLURRY A oe ELIZ CONVEN- PRODUCT OXYGEN oO, ss = aa Ti ONAL mw oe CLEANUP TEXACO en GASIFIER er N TO COMBUSTOR HIGH-PRESSURE H SYNGAS I & STEAM FEED WATER — RADIANT SULFUR | SYNGAS SYNGAS REMOVAL - COOLER SLAG BLACK WATER STEAM DISPOSAL RECYCLED el ae HOT EXHAUST STEAM rae ext HEAT RECOVERY STEAM * SULFURIC ACID GENERATOR PLANT STEAM TURBINE Project Objective To demonstrate IGCC technology in a greenfield commer- cial electric utility application at the 250-MWe size using an entrained flow, oxygen blown, gasifier with full heat recovery, conventional cold-gas cleanup, and an advanced gas turbine with nitrogen injection for power augmenta- tion and NO, control. Technology/Project Description Coal/water slurry and oxygen are reacted at high tempera- ture and pressure to produce a medium BTU syngas in a Texaco gasifier. Molten ash flows out of the bottom of the gasifier into a water-filled sump where it is forms a solid slag. The syngas moves from the gasifier to a high tem- perature heat-recovery unit, which cools the syngas while generating high pressure steam. The cooled gases flow to a water wash for particulate removal. Next, a COS hy- drolysis reactor converts one of the sulfur species in the gas to a form which is more easily removed. The syngas is then further cooled before entering a con- ventional amine sulfur removal system. The amine system keeps SO, emissions below 0.15 1b/10° Btu (97% capture). The cleaned gases are then reheated and routed to a combined-cycle system for power genera- tion. (A 10 MWe slipstream for hot syngas cleanup system had been envisioned but has been placed on hold pending resolution of technical problems.) A GE MS 7001FA combustion turbine (CT) generates 192 MWe. Thermal NO, is controlled to below 0.27 Ib/ 10° Btu by injecting nitrogen. A steam turbine uses steam produced by cooling the syngas and superheated with the CT exhaust gases in the HRSG to produce an addi- tional 124-MWe. The plant heat rate is 9350 Btu/K WH (HHV), which is an efficiency of 38.4% (LHV). Advanced Electric Power Generation Calendar Year ors 1988 1989 1990 1991 3° 4)/1 2 3 4 1 2 3 4 1 2 3 12/89 Preaward t Operation initiated 9/96 Construction completed 8/96 Preoperational tests initiated 6/96 Environmental monitoring plan completed 5/96 Design completed 8/94 NEPA process completed (EIS) 8/17/94 Construction started 8/94 Cooperative agreement awarded 3/11/91 DOE selected project (CCT-III)_ 12/19/89 Operation Project completed/final report issued 10/01* Operation completed 10/01* *Projected date “*Years omitted Project Status/Accomplishments Since Polk Power Station’s first gasifier run in July 1996, the gasifier has operated over 16,000 hours. The station generated more than 4.5 million MWh of elec- tricity from syngas it produced through September 1999. During one six-month period, the gasifier had an 83.5% on-stream factor and the combined-cycle avail- ability was 94%. The gasifier and combustion turbine continuous operation records are 37 and 51 days, re- spectively. Several modifications to the original design and procedures were required to achieve the recent high avail- ability, including: (1) removing or modifying some of the heat exchangers in the high temperature heat recovery system and making compensating adjustments in the balance of the system to resolve ash plugging problems, (2) additional solid particle erosion protection for the combustion turbine to protect the machine from ash, (3) implementing hot restart procedures to reducer gasifier restart time by 18 hours, (4) adding a duplicate fines Advanced Electric Power Generation handling system to deal with increased fines loading resulting from lower than expected carbon conversion, (5) revising operating procedures to deal with high shell temperatures in the dome of the radiant syngas cooler, and (6) making various piping changes to cor- rect for erosion and corrosion in the process and coal/ water slurry systems. A COS hydrolysis unit was installed in 1999 to further reduce SO, emissions, en- abling the station to meet recent more stringent emis- sions restrictions. Tampa Electric will face two major challenges in 2000, both of which have efficiency improvement as a major objective. The first will be to commission the slag handling system that separates the slag into its main constituents, a useful by-product for sale and a suitable fuel for recycle. The second will be to upgrade the brine concentration system. Applications The project was presented the 1997 Powerplant Award by Power magazine. In 1996 the project received the asso- ciation of Builders and Contractors Award for con- struction quality. Several awards were presented for 1993 Ecological Society of America Corporate Award and 1993 Timer using and innovative siting process: Powers Conflict Resolution Award from the State of Florida, and the 1991 Florida Audubon Society Corporate Award. As a result of the Polk Power Station demonstration, Texaco-based IGCC can be considered commercially and environmentally suitable for electric power generation utilizing a wide variety of feedstocks. Sulfur capture for the project is greater than 98%, while NO, emission re- duction are 90% that of a conventional pulverized coal- fired power plant. The integration and control approaches utilized at Polk can also be applied in IGCC projects using different gasification technologies. TECO Energy is not only actively working with Texaco to commercialize the technology in the United States, but has been contacted by European power pro- duces to discuss possible technical assistance on using the gasifier technology. Program Update 1999 5-121 Advanced Electric Power Generation Integrated Gasification Combined Cycle Wabash River Coal Gasification Repowering Project Participant Wabash River Coal Gasification Repowering Project Joint Venture (a joint venture of Dynegy and PSI En- ergy, Inc.) Additional Team Members PSI Energy, Inc.—host Dynegy (formerly Destec Energy, Inc., a subsidiary of Natural Gas Clearinghouse)—engineer and gas plant operator Location West Terre Haute, Vigo County, IN (PSI Energy’s Wabash River Generating Station, Unit No. 1) Technology Integrated gasification combined-cycle (IGCC) using Global Energy’s two-stage pressurized, oxygen-blown, entrained-flow gasification system Plant Capacity/Production 296-MWe (gross), 262-MWe (net) Coal Illinois Basin bituminous Project Funding Total project cost $438,200,000 100% DOE 219,100,000 50 Participant 219,100,000 50 Project Objective To demonstrate utility repowering with a two-stage pres- surized oxygen-blown entrained-flow IGCC system, in- cluding advancements in the technology relevant to the use of high-sulfur bituminous coal; and to assess long- 5-122 Program Update 1999 SYNGAS > ENTRAINED-FLOW GASIFIER — PARTICULATE REMOVAL —— SYNGAS COOLER SLURRY PLANT COAL—> WATER-> Bian ‘ so -—_ SLAG OXYGEN Bree QUENCH PLANT WATER BO i SLAG BY-PRODUCT PRY ’ STEAM TURBINE STEAM | | STEAM } stack | | A CANDLE FILTER iY SULFUR REMOVAL & — RECOVERY| LIQUID SULFUR: BY-PRODUCT | ” Jeng im / —_ GEN. COMBUSTION TURBINE FEED WATER term reliability, availability, and maintainability of the system at a fully commercial scale. Technology/Project Description The Destec process features an oxygen-blown, continu- ous-slagging, two-stage entrained flow gasifier. Coal is slurried, combined with 95% pure oxygen, and injected into the first stage of the gasifier, which operates at 2600 °F/400 psig. In the first stage, the coal slurry under- goes a partial oxidation reaction at temperatures high enough to bring the coal’s ash above its melting point. The fluid ash falls through a tap hole at the bottom of the first stage into a water quench, forming an inert vitreous slag. The syngas flows to the second stage, where addi- tional coal slurry is injected. This coal is pyrolyzed in an endothermic reaction with the hot syngas to enhance syngas heating value and improve efficiency. The syngas then flows to the syngas cooler, es- sentially a firetube steam generator, to produce high- pressure saturated steam. After cooling in the syngas cooler, particulates are removed in a hot/dry filter and recycled to the gasifier. The syngas is further cooled in a series of heat exchangers. The syngas is water- scrubbed to remove chlorides and passed through a catalyst that hydrolyzes carbonyl sulfide into hydrogen sulfide. Hydrogen sulfide is removed in the acid gas removal system using MDEA-based absorber/stripper columns. A Claus unit is used to produce elemental sulfur as a salable by-product. The “sweet” gas is then moisturized, preheated, and piped to the power block. The power block consists of a single 192-MWe GE MS 7001FA (Frame 7 FA) gas turbine, a Foster Wheeler single-drum heat recovery steam generator with reheat, and a 1952 vintage Westinghouse reheat steam turbine. Advanced Electric Power Generation Calendar Year 1991 3 4/1 2 3 4/1 2 3 4/1 2 3 1996 1. 2 3 4/1 2 3 4/1 2 3 4/41 2001 9/91 7/192 Preaward | DOE selected project (CCT-IV) 9/12/91 Cooperative agreement awarded 7/28/92 Design and Construction Operation Operation initiated 11/95 Construction completed 11/95 Preoperational tests initiated 8/95 Design completed 5/94 Environmental monitoring plan completed 7/9/93 Groundbreaking ceremony 7/7/93 NEPA process completed (EA) 5/28/93 Project completed/final report issued 4/00* Demonstration completed 12/99" *Projected date Project Status/Accomplishments The Wabash River Coal Gasification Repowering Project, which is the world’s largest single train IGCC plant oper- ating commercially, is currently in its fourth year of opera- tion and nearing the end of the planned demonstration. The Dynegy gasification process (formerly known as the Dow gasification process) has demonstrated the ability to operate at full load while meeting environmental require- ments for SO, and NO, emissions. The facility is demon- strating a heat rate of 8,910 Btu/kWh (HHV) and SO, emissions of 0.1 Ib/10° Btu. The total NO, emissions are 0.15 Ib/10° Btu and particulate emissions are below de- tectable limits. The facility has operated approximately 15,000 hours and processed approximately 1.5 million tons of coal to produce about 23 x 10! Btu of syngas. The GE Frame 7 FA gas turbine has performed well on syngas, but not without problems. In addition to cracking in the syngas flow sleeves and in the combustion liners previously reported, compressor rows 4 through 17 of the rotor and stator incurred damage in mid-March 1999, resulting in a three month outage. The outage allowed time to focus on other issues. Efforts are now Advanced Electric Power Generation focused on reducing nuisance trips in the air separa- tion unit, which produces 2,060 tons/day of 95% pure oxygen. The particulate removal system has performed well since a major improvement project in 1997. Down- time associated with the barrier filter system had been reduced by nearly 80% over the first commercial year statistics. An ongoing filter element development program reduced 1998 filter-related downtime by an additional 66 percent over 1997. An extended outage adversely affected the 1999 operating statistics; how- ever, the facility was able to set another quarterly pro- duction record of 2.7 x 10'? Btu. In 1999, the annual contract capacity was 69.9% and the annual availability was 79.1%. For comparison, the 1998 annual availabil- ity was 71.8%. Destec Energy and CINergy Corp./PSI Energy re- ceived the 1996 Powerplant Award from Power maga- zine. Sargent & Lundy, engineer for the combined-cycle facility, won the American Consulting Engineers Council’s 1996 Engineering Excellence Award. On December 31, 1999, the demonstration was completed and Global Energy, Inc. purchased Dynegy’s gasification assets and technology. Global Energy plans to market the technology under the name “E-Gas Technology™.” Commercial Applications Throughout the United States, particularly in the Midwest and East, there are more than 95,000-MWe of existing coal-fired utility boilers over 30 years old. Many of these plants are without air pollution controls and are candidates for repowering with IGCC technology. Re- powering these plants with IGCC systems will improve plant efficiencies and reduce SO,, NO, particulate, and CO, emissions. The modularity of the gasifier technol- ogy will permit a range of units to be considered for repowering, and the relatively short construction sched- ule for the technology will allow utilities greater flexibility in designing strategies to meet load requirements. Also, the high degree of fuel flexibility inherent in the gasifier design will provide utilities with more choice in selecting fuel supplies to meet increasingly stringent air quality regulations. Program Update 1999 5-123 Advanced Electric Power Generation Advanced Combustion/Heat Engines Advanced Electric Power Generation Program Update 1999 5-125 Advanced Electric Power Generation Advanced Combustion/Heat Engines Healy Clean Coal Project Participant Alaska Industrial Development and Export Authority Additional Team Members Golden Valley Electric Association—host and operator Stone and Webster Engineering Corp.—engineer TRW Inc., Space & Technology Division—combustor technology supplier The Babcock & Wilcox Company (B&W) (which has acquired assets of Joy Environmental Technologies, Inc.)—spray dryer absorber technology supplier Usibelli Coal Mine, Inc.—coal supplier Location Healy, Denali Borough, AK (adjacent to Healy Unit No. 1) Technology TRW’s advanced entrained (slagging) combustor; Bab- cock & Wilcox’s spray dryer absorber with sorbent recycle Plant Capacity/Production 50-MWe (nominal) Coal Usibelli subbituminous 50% run-of-mine (ROM) and 50% waste coal Project Funding Total project cost $242,058,000 100% DOE 117,327,000 48 Participant 124,731,000 52 Project Objective To demonstrate an innovative new power plant design featuring integration of an advanced combustor and heat recovery system coupled with both high- and low-tem- perature emissions control processes. 5-126 — Program Update 1999 PRECOMBUSTOR: MAIN COMBUSTORS SLAG Taps — SLAG & BOTTOM ASH TO DISPOSAL SORBENT ACTIVATION STEAM TURBINE as SOLID WASTE TO DISPOSAL GEN. ARO Technology/Project Description The project involves two unique slagging combustors. Emissions of SO, and NO, are controlled using TRW’s slagging combustion systems with staged fuel and air and limestone injection for SO, control. Additional SO, is removed using B& W’s activated recycle spray dryer ab- sorber system. A coal-fired precombustor increases the air inlet tem- perature for optimum slagging performance. The slagging combustors are side mounted, injecting the combustion products vertically into the boiler. The main slagging combustor consists of a water-cooled cylinder that slopes toward a slag opening. The precombustor burns 25-40% of the total coal input. The remaining coal is injected axially into the combustor, rapidly entrained by the swirl- ing precombustor gases and additional air flow, and burned under substoichiometric conditions for NO, control. The ash forms molten slag, which accumulates on the water- cooled walls and is driven by aerodynamic and gravita- tional forces through a slot into the slag recovery section. About 70-80% of the ash is removed as molten slag. The hot gas is then ducted to the furnace where, to ensure complete combustion, additional air is supplied from the tertiary air windbox to NO, ports and to final overfire air ports. Pulverized limestone (CaCO,) for SO, control is fed into the combustor where it is flash calcined (converting CaCO, to lime (CaO). The mixture of this CaO and ash not slagged, called flash-calcined material, is removed in the fabric filter system. Most of the flash-calcined mate- rial is used to form a 45% flash-calcined-material solids slurry. The SO, in the flue gas reacts with the slurry drop- lets as water is simultaneously evaporated. The SO, is further removed from the flue gas by reacting with the dry flash-calcined material on the baghouse filter bags. Advanced Electric Power Generation Calendar Year +e +e 1990 1993 2 3 4/1 2 3 4/1 2 3 4/] 1 2 2000 2002 Cooperative agreement awarded 4/11/91 Design started 7/90 DOE selected project (CCT-IIl) 12/19/89 Design completed 10/93 NEPA process completed (EIS) 3/10/94 Project Status/Accomplishments The project site is adjacent to the existing Healy Unit No. 1 near Healy, Alaska, and to the Usibelli coal mine. Power is supplied to the Golden Valley Electric Associa- tion (GVEA). The plant uses 900 tons/day of subbitumi- nous and waste coal. To address concerns about potential impact to the nearby Denali National Park and Preserve, DOE, the National Park Service, GVEA, and the project participant entered into an agreement to reduce emissions from Unit No. | so that combined emissions from the two units will be only slightly greater than those currently emitted from Unit No. | alone. Total site emissions will be further reduced to current levels if necessary to protect the park. The initial firing of the entrained slagging combus- tion system on coal began in January 1998. The results from environmental compliance testing showed that NO, emissions of 0.26 Ib/10° Btu, SO, emissions of 0.01 Ib/10° Btu, and particulate emissions of 0.0047Ib/10° Btu were achieved. NO,, SO,, and particulate emission measures were within permit requirements. The permit requires Advanced Electric Power Generation Design and Construction Ground breaking/ construction started 5/30/95 Operation initiated 1/98 Construction completed 11/97 Preoperational tests initiated 8/97 Environmental monitoring plan completed 4/11/97 Operation 6/00 Project completed/final report issued 6/00* DOE cost-shared operation completed 12/99* *Projected date “Years omitted NO, emissions to be less than 0.35 Ib/10° Btu, SO, emis- sions less than 0.086 Ib/10° Btu, and particulate emissions less than 0.03 Ib/10° Btu. The stringent SO, emission level required by the permit is significantly lower than the 1.2 Ib/10° Btu NSPS limit. The following modifications were made during a routine outage completed in January 1999: combustor improvements to minimize slag buildup in the precombus- tor/combustor, addition of an acoustical silencer to the ID fan area, and insertion of a flow distribution device prior to the baghouse to minimize bag wear. In addition, soot blowers were added in July 1999 to reduce furnace slag buildup around the combustor outlet. During a 90-day capacity factor test that began on August 17, 1999, the plant achieved an average capacity factor of over 90% through September 30, 1999. The test requirement is a capacity factor of 85%. Capacity factor testing and sus- tained operations testing will continue into December 1999. Commercial Applications This technology is appropriate for any size utility or industrial boiler in new and retrofit uses. It can be used in coal-fired boilers as well as in oil- and gas-fired boil- ers because of its high ash-removal capability. How- ever, cyclone boilers may be the most amenable type to retrofit with the slagging combustor because of the limited supply of high-Btu, low-sulfur, low-ash-fusion- temperature coal that cyclone boilers require. The commercial availability of cost-effective and reliable systems for SO,, NO,, and particulate control is impor- tant to potential users planning new capacity, repower- ing, or retrofits to existing capacity in order to comply with CAAA requirements. Program Update 1999 5-127 Advanced Electric Power Generation Advanced Combustion/Heat Engines Clean Coal Diesel Demonstration Project Participant Arthur D. Little, Inc. Additional Team Members University of Alaska at Fairbanks—host and cofunder Alaskan Science & Technology Foundation—cofunder Coltec Industries Inc.—diesel engine technology vendor Energy and Environmental Research Center, University of North Dakota (EERC)—fuel preparation technology vendor R.W. Beck, Inc.—architect/engineer, designer, constructor Usibelli Coal Mine, Inc.—coal supplier Location Fairbanks, AK (University of Alaska facility) Technology Coltec’s coal-fueled diesel engine Plant Capacity/Production 6.4-MWe (net) Coal Usibelli Alaskan subbituminous Project Funding Total project cost $47,636,000 100% DOE 23,818,000 50 Participant 23,818,000 50 Project Objective To prove the design, operability, and durability of the coal diesel engine during 6,000 hours of operation; verify the design and operation of an advanced drying/slurrying process for subbituminous Alaskan coals; and test the coal slurry in the diesel and a retrofitted oil-fired boiler. 5-128 — Program Update 1999 EXHAUST GAS SLURRY PLANT I COAL-FUELED DIESEL ENGINE BAGHOUSE ie \ | | WASTE HEAT (FGD)_, >» fea) BOILER \sScR) feel X _ Ey | STACK , STEAM FOR SPACE HEATING Technology/Project Description The project is based on the demonstration of an 18-cylin- der, heavy duty engine (6.4-MWe) modified to operate on Alaskan subbituminous coal. The clean coal diesel tech- nology, which uses a low-rank coal-water-fuel (LRCWF), is expected to have very low NO, and SO, emission levels (50-70% below current New Source Performance Stan- dards). In addition, the demonstration plant is expected to achieve 41% efficiency, while future plant designs are expected to reach 48% efficiency. This will result in a 25% reduction in CO, emissions compared to conven- tional coal-fired plants. The LRCWF is prepared using an advanced coal drying process that allows dried coal to be slurried in water. In addition to the LRCWF being capable for use in the coal-fueled diesel engine, the LRCWF is ex- pected to be an alternative to fuel oil in conventional oil-fired industrial boilers. Advanced Electric Power Generation Calendar Year 1993 1994 1995 4/1 2 3 4/1 2 3 4/1 2 3 4)]1 2000 2002 2 3 4 1 2 3 4 12 3 4 1 2 Project restructured 8/96 Design and Construction Coaltec 2-cylinder engine test on LRCWF NEPA process completed (EA) 6/2/97 Cooperative agreement awarded 7/12/94 DOE selected project (CCT-V) 5/4/93 Construction started 6/98 Design completed 1/99 Environmental monitoring plan completed 2/99 Project Status/Accomplishments The project has passed several milestones. A 95% design review was conducted in January 1999 at the University of Alaska, Fairbanks (UAF). Representa- tives from Coltec, A.D. Little, UAF, DOE, and GHEMM (construction contractor) were in attendance. The latest design eliminates the need for a sorbent injection system because the Usibelli mine was able to locate a very clean coal seam with less than 0.2% sulfur in the ash. The sorbent injection system originally proposed for the coal diesel was designed for use with bitumi- nous coals with greater than 2.0% sulfur levels. Coltec, the diesel engine manufacturer, worked with EERC to design new injectors with sapphire orifices sized for the volume of LRCWF required to operate the engine at full load. Earlier designs were based on higher energy density bituminous coals. The 18-cylinder engine arrived in January 1999, but extremely cold weather prevented movement into the facilities building until the end of February 1999. The 18- cylinder diesel engine was operated on oil during Septem- Advanced Electric Power Generation ber 1999. Prior to the 18-cylinder engine tests on coal slurry, Coltec will run their 2-cylinder test engine to optimize the operation settings, verify coal fuel perfor- mance, and finalize hard coatings for critical compo- nents. Tests are scheduled for May—September 2000. Samples of the Usibelli coal were sent to CQ Inc., for washability tests; to ADL for wear tests; and to EERC for preliminary hot water drying tests and bench wear tests. Several plant design changes were made in order to keep the project within budget. Notably, a small commercial oil-fired boiler will be converted for coal slurry tests instead of an industrial-scale boiler, and several of the slurry holding tanks will be located closer to the diesel engine to reduce underground piping. Final design of the LRCWF processing plant has been completed. Construction of the LRCWF has been delayed until May 2001 due to funding shortages. A revised plan and schedule for the demonstration test of the 18-cylinder diesel on coal slurry is being developed. 6/02 4/04 Operation | Operation completed 1/04* Project completed/final report issued 4/04* Coal Diesel Operation initiated 6/02* *Projected date Commercial Applications The U.S. diesel market is projected to exceed 60,000- MWe (over 7,000 engines) through 2020. The world- wide market is 70 times the U.S. market. The technol- ogy is particularly applicable to distributed power generation in the 5- to 20-MWe range, using indig- enous coal in developing countries. The net effective heat rate for the mature diesel system is expected to be 6,830 Btu/kWh (48%), which makes it very competitive with similarly sized coal- and fuel oil-fired installations. Environmental emissions from commercial diesel systems should be reduced to levels between 50% and 70% below NSPS. The estimated installation cost of a mature commercial unit is approxi- mately $1,300/kW. Program Update 1999 5-129 Coa Coal Processing for Clean Fuels 1 Processing for Clean Fuels Program Update 1999 5-131 Coal Processing for Clean Fuels Indirect Liquefaction Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process Participant Air Products Liquid Phase Conversion Company, L.P. (a limited partnership between Air Products and Chemicals, Inc., the general partner, and Eastman Chemical Company) Additional Team Members Air Products and Chemicals, Inc—technology supplier and cofunder Eastman Chemical Company—host, operator, synthesis gas and services provider ARCADIS Geraghty & Miller—fuel methanol tester and cofunder Electric Power Research Institute—utility advisor Location Kingsport, Sullivan County, TN (Eastman Chemical Company’s Integrated Coal Gasification Facility) Technology Air Products and Chemicals’ liquid phase methanol process Plant Capacity/Production 80,000 gallons/day of methanol (nominal) Coal Eastern high-sulfur bituminous, 3—5% sulfur Project Funding Total project cost $213,700,000 100% DOE 92,708,370 43 Participant 120,991,630 57 LPMEOH is a trademark of Air Products and Chemicals, Inc. 5-132 Program Update 1999 STEAM< FEED=*| WATER METHANOL/ DME SYNTHESIS REACTOR oyeeN CHEMICAL — | SYNTHESIS GAS PRODUCTION COAL . _ CARBON 1 SLURRY DIOXIDE suLFURFREE | METHANOL ~~ SYNTHESIS GAS RECOVERY STEAM TTT | CYCLONE | | SEPARATOR -L— et ru SECONDARY =| | A SULFUR/ METHANOL/DME 7 PRIMARY CARBONYL STORAGE METHANOT psa SLAG | GAS DME TREATMENT eee ey MAKEUP SULFUR SLURRY OIL CATALYST PREPARATION MAKEUP. CATALYST CATALYST SLURRY RECOVERY Project Objective To demonstrate on a commercial scale the production of methanol from coal-derived synthesis gas using the LPMEOH™ process; to determine the suitability of metha- nol produced during this demonstration for use as a chemical feedstock or as a low-SO, emitting, low-NO, emitting alternative fuel in stationary and transportation applications; and to demonstrate, if practical, the produc- tion of dimethyl! ether (DME) as a mixed coproduct with methanol. Technology/Project Description This project is demonstrating, at commercial scale, the LPMEOH™ process to produce methanol from coal- derived synthesis gas. The combined reactor and heat removal system is different from other commercial metha- nol processes. The liquid phase not only suspends the catalyst but functions as an efficient means to remove the heat of reaction away from the catalyst surface. This feature permits the direct use of synthesis gas streams as feed to the reactor without the need for water-gas shift conversion. Methanol fuel testing is being conducted in off-site stationary and mobile applications, such as fuel cells, buses, and distributed electric power generation. Design verification testing for the production of DME as a mixed coproduct with methanol for use as a storable fuel is planned for fall 1999, and a decision on whether or not to demonstrate at Kingsport will be made. Eastern high- sulfur bituminous coal (Mason seam) containing 3% sulfur (5% maximum) and 10% ash is being used. Coal Processing for Clean Fuels Calendar Year 1991 3 4/1 2 3 4/1 2 3 4/1 2 8 = 2/89 10/92 Preaward | I DOE selected Project resited to project (CCT-III) Kingsport, TN 12/19/89 10/93 Project transferred to Air Products Liquid Phase Conversion Company, L.P. 3/95 Design and Construction Operation initiated 4/97 Preoperational tests initiated 1/97 Construction completed 1/97 Design completed 6/96 Construction started 10/95 NEPA process completed (EA) 6/30/95 Cooperative agreement awarded 10/16/92 Environmental monitoring plan completed 8/29/96 Operation Operation completed 3/01* Project completed/final report issued 12/01* * Projected date Project Status/Accomplishments Construction was completed in January of 1997. Follow- ing commissioning and shakedown activities, the first production of methanol from the 80,000 gal/day unit occurred on April 2, 1997. The first stable operation of the process demonstration unit at nameplate capacity occurred on April 6, 1997. A stable test period at over 92,000 gal/day revealed no system limitations. The startup also proceeded without injury or environmental incidents. The hydrogen-to-carbon monoxide (H,/CO) ratio in the reactor feed stream was varied from 0.4 to 5.6 with no negative effects on catalyst performance. Operation of the demonstration unit confirmed the engineering meth- ods used in the design of the LPMEOH™ reactor, and several parameters (such as the overall heat transfer coef- ficient of the internal heat exchanger) were demonstrated at greater than 115% of design levels. The LPMEOH™ process demonstration unit contin- ues to exceed expectations. Since startup in April 1997, about 43 million gallons of methanol have been produced Coal Processing for Clean Fuels and plant availability has exceeded 97%. Availability in 1998 and 1999 was in excess of 99.7%. During 1998, catalyst life significantly improved due primarily to the elimination of trace iron contamination, which may have been caused by construction debris in the system, and to lower operating temperatures to meet production rates. Catalyst life has now met or exceeded the results obtained on poison-free synthesis gas in DOE’s LaPorte (Texas) Process Development Unit. In March 1999, an inspection of all pressure vessels revealed no problems with erosion or corrosion. To fur- ther mitigate the effects of arsenic (a catalyst poison), arsenic removal capacity was increased in guard beds located both upstream and within the LPMEOH™ pro- cess during June 1999, Analytical work performed imme- diately after the guard bed systems change confirmed that the levels of arsenic in the feed gas had been reduced to very low levels. The effect of this change on catalyst performance and the level of all potential poisons will continue to be monitored during the ongoing plant operation. Commercial Applications The LPMEOH™ process has been developed to en- hance IGCC power generation by producing a clean- burning, storable-liquid fuel (methanol) from clean coal- derived gas. Methanol also has a broad range of com- mercial applications; it can be substituted for conven- tional fuels in stationary and mobile combustion appli- cations and is an excellent fuel for utility peaking units. Methanol contains no sulfur and has exceptionally low NO, characteristics when burned. DME has several commercial uses. In a storable blend with methanol, the mixture can be used as peaking fuel in IGCC electric power generating facilities. Blends of methanol and DME also can be used as a chemical feedstock for the synthesis of chemicals or new oxygenate fuel additives. Pure DME is an environmentally friendly aerosol for personal products. Typical commercial-scale LPMEOH™ units are expected to range in size from 50,000—300,000 gal/day of methanol produced when associated with commercial IGCC power generation trains of 200-500 MWe. Program Update 1999 5-133 Coal Processing for Clean Fuels Coal Preparation Technologies Self-Scrubbing Coal™: An Integrated Approach to Clean Air Participant Custom Coals International Additional Team Members Pennsylvania Power & Light Company—host Richmond Power & Light—host Centerior Service Company—host Locations Central City, Somerset County, PA (advanced coal-cleaning plant) Lower Mt. Bethel Township, Northampton County, PA (combustion tests at Pennsylvania Power & Light’s Martin’s Creek Power Station, Unit No. 2) Richmond, Wayne County, IN (combustion tests at Richmond Power & Light’s Whitewater Valley Generating Station, Unit No. 2) Ashtabula, Trumbull County, OH (combustion tests at Centerior Energy’s Ashtabula C) Technology Coal preparation using Custom Coals’ advanced physical coal-cleaning and fine magnetite separation technology plus sorbent addition technology Plant Capacity/Production 500 tons/hr Coal Illinois No. 5 (2.7% sulfur); Lower Freeport (3.9% sul- fur); and Lower Kittanning (1.8% sulfur) Self-Scrubbing Coal and Carefree Coal are trademarks of Custom Coals International. 5-134 Program Update 1999 RUN-OF-MINE COAL | ADVANCED TECHNOLOGY COAL CLEANING PLANT CLEANED COAL COMPLIANCE COAL CYCLONE COAL BREAKER ULTRA- CLEANED FINE COAL COAL ASH | MAGNETITE ee SORBENT ASH & PYRITIC ADDITION SULFUR TO fr PG POWER STATION = : CAREFREE COAL SELF-SCRUBBING COAL Project Funding Carefree Coal™ is produced by breaking and screen- Total project cost $87,386,102 100% ing run-of-mine coal and by using innovative dense- DOE 37,994,437 43 medium cyclones and finely sized magnetite to remove up Participant 49,391,665 57 to 90% of the pyritic sulfur and most of the ash. Carefree Project Objective To demonstrate advanced coal-cleaning unit processes to produce low-cost compliance coals that can meet the requirements for commercial-scale utility power plants to satisfy provisions of the CAAA. Technology/Project Description An advanced coal-cleaning plant has been designed, blending existing and new processes, to produce two types of compliance coals—Carefree Coal™ and Self- Scrubbing Coal™—from various feedstocks. Coal™ is designed to be a competitively-priced, high-Btu fuel that can be used without major plant modifications or additional capital expenditures. Self-Scrubbing Coal™ is produced by taking Care- free Coal™, with its reduced pyritic sulfur and ash con- tent, and adding to it sorbents, promoters, and catalysts. Self-Scrubbing Coal™ is expected to achieve compliance with virtually any U.S. coal feedstock through in-boiler absorption of SO, emissions. The reduced ash content of the Self-Scrubbing Coal™ permits addition of relatively large amounts of sorbent without exceeding ash specifica- tions of boilers or overloading electrostatic precipitators. Coal Processing for Clean Fuels Calendar Year 1991 1992 9) 4:) 14) 2) 3] 14 hal 2, 3) 4) ia) 2 3. 1995 2001 9/91 10/92 Preaward DOE selected project (CCT-IV) 9/12/91 Design and Construction 2/97 Operation Project on hold Operation initiated 2/96 Preoperational tests initiated 11/95 Construction completed 11/95 Design completed 12/94 NEPA process completed (EA) 2/14/94 Construction started 12/93 Cooperative agreement awarded 10/29/92 Project Status/Accomplishments Startup began in late December 1995, and the first coal was processed in February 1996. In May 1996, the facil- ity reached its design capacity. Equipment and circuit optimization testing began immediately thereafter and continued throughout 1996. A Carefree Coal™ test burn (cleaned Lower Kittan- ning coal) at Martin’s Creek Power Station was conducted in mid-November 1996. Although plant optimization was not completed, the overall product made for the test was consistent with the current quality of the plant feed coal. The unit experienced some opacity problems due to the low sulfur in the coal and a marginal electrostatic precipitator. High organic sulfur in the raw coal created problems with the ability to produce compliance quality clean coal. Further, difficulties with the plant resulted in an excessive amount of material going to the refuse pond, and plant operation was suspended in February 1997. Financial problems ensued and, despite efforts to resolve the matter, the project was placed in Chapter 11. Due to Custom Coal Processing for Clean Fuels Coals’ inability to find a buyer for the facility, the Cus- tom Coals Laurel facility was sold at auction on Decem- ber 16, 1998, to C.J. Betters Enterprises of Monaca, Pennsylvania. C.J. Betters has met with DOE to dis- cuss continuation of the project and was working to complete a continuation package. However, C.J. Bet- ters was unable to locate a suitable partner to assist with the completion of the project. The project’s per- formance period has expired. Prior to the publication of this report, the project has completed closeout proce- dures and is no longer active. Commercial Applications While many utilities can use Carefree Coal™ to comply with SO, emissions limits, others cannot due to the high content of organic sulfur in their coal feedstocks. When compliance coal cannot be produced by reducing pyritic sulfur, Self-Scrubbing Coal™ can be produced to achieve compliance. Commercialization of Self-Scrubbing Coal™ has the potential of bringing into compliance about 164 million tons/yr of bituminous coal that cannot meet emissions limits through conventional coal-cleaning. This repre- sents more than 38% of the bituminous coal burned in 50-MWe or larger U.S. generating stations. Program Update 1999 5-135 Coal Processing for Clean Fuels Coal Preparation Technologies Advanced Coal Conversion Process Demonstration Participant Western SynCoal LLC (formerly Rosebud SynCoal Partnership; a subsidiary of Montana Power Company’s Energy Supply Divisions) Additional Team Members None Location Colstrip, Rosebud County, MT (adjacent to Western Energy Company’s Rosebud Mine) Technology Western SynCoal LLC’s Advanced Coal Conversion Process for upgrading low-rank subbituminous and lignite coals Plant Capacity/Production 45 tons/hr of SynCoal” product Coal Powder River Basin subbituminous (Rosebud Mine), 0.5-1.5% sulfur, plus tests of other subbituminous coals and lignites Project Funding Total project cost $105,700,000 100% DOE 43,125,000 41 Participant 62,575,000 59 Project Objective To demonstrate Western SynCoal LLC’s Advanced Coal Conversion Process (ACCP) to produce SynCoal”, a stable coal product having a moisture content as low as 1%, sulfur content as low as 0.3%, and heating value up to 12,000 Btu/Ib. SynCoal is a registered trademark of the Rosebud SynCoal Partnership. 5-136 Program Update 1999 DUST COLLECTOR _| DRYER/REACTORS (oo COAL ¥ HOT INERT. FLUE GAS HEATER * COOLING VIBRATING FLUIDIZED COOLER FINE STRATIFIERS HIGH-MOISTURE LOW-RANK FEED COAL FLUIDIZED-BED SEPARATORS FLUIDIZED-BED SEPARATORS SYNCOAL’ FINES SYNCOAL” COARSE STRATIFIERS as Technology/Project Description The process demonstrated is an advanced thermal coal conversion process coupled with physical cleaning tech- niques to upgrade high-moisture, low-rank coals to pro- duce a high-quality, low-sulfur fuel. The raw coal is screened and fed to a vibratory fluidized-bed reactor where surface moisture is removed by heating with hot combustion gas. Coal exits this reactor at a temperature slightly higher than that required to evaporate water and flows to a second vibratory reactor where the coal is heated to nearly 600 °F. This temperature is sufficient to remove chemically-bound water, carboxyl groups, and volatile sulfur compounds. In addition, a small amount of tar is released, partially sealing the dried product. Particle shrinkage causes fracturing, destroys moisture reaction sites, and liberates the ash-forming mineral matter. The coal is then cooled to less than 150 °F by contact with an inert gas in a vibrating fluidized-bed cooler. The cooled coal is sized and fed to deep bed stratifiers where air pressure and vibration separate mineral matter, includ- ing much of the pyrite, from the coal, thereby reducing the sulfur content of the product. The low specific grav- ity fractions are sent to a product conveyor while heavier fractions go to fluidized-bed separators for additional ash removal. The fines handling system consolidates the coal fines that are produced throughout the ACCP facility. The fines are gathered by screw conveyors and transported by drag conveyors to a bulk cooling system. The cooled fines are blended with the coarse product, stored in a 250-ton capacity bin until loaded into pneumatic trucks for off-site sales, or returned to the mine pit. Coal Processing for Clean Fuels I catnaar Year te 1988 1989 2002 9/90 Preaward DOE selected project (CCT-l) 12/9/88 Cooperative agreement awarded 9/21/90 Design and Construction 6/92 I Test operation initiated 6/92 Environmental monitoring plan completed 4/7/92 Construction completed 2/92 Preoperational tests initiated 12/91 Design completed 8/91 Ground breaking/construction started 3/28/91 NEPA process completed (EA) 3/27/91 Operation Operation completed 1/01* Project completed/final report issued 6/01* * Projected date “Years omitted Project Status/Accomplishments The ACCP facility was scheduled to complete demonstra- tion operations in January 1999 but was granted a two- year no-cost extension. The ACCP facility continues to operate using a dedicated pneumatic feed system to sup- ply SynCoal” to Montana Power’s 330-MWe Colstrip No. 2 under an eight-year contract. The ACCP facility has processed over 2.3 million tons of raw coal to produce over 1.5 million tons of SynCoal®. The SynCoal” is used by electric utilities and industrial facilities (primarily cement and lime plants). The demonstration unit can process 1,000 tons per day of SynCoal" and is one-tenth the size of a commercial facility. The ACCP facility takes advantage of existing mine infrastructure. Over a four-year period, 321,528 tons of SynCoal® was burned at the 160-MWe J.E. Corette plant in Billings, Montana. The testing involved both handling and combustion tests of dust stabilization en- hancement (DSE, a dilute water-based suppressant) treated SynCoal” in a variety of blends. These blends ranged from 15-85% SynCoal® with raw coal. Overall, Coal Processing for Clean Fuels the results indicate that a 50/50 blend of SynCoal"/raw coal provides improved plant performance, including reduced SO, emissions. The use of SynCoal” permitted deslagging the boiler at full load, thereby eliminating costly ash shedding operations. The result was reduced gas flow resistance in the boiler and convection passage, which reduced fan horsepower and improved heat transfer in the boiler, leading to a 3-MWe net increase. Three different feedstocks were tested at the ACCP facility—North Dakota lignite, Knife River lignite, and Amax subbituminous coal. Approximately 190 tons of the SynCoal” product produced with the North Dakota lignite was burned at the 250-MWe cyclone-fired Milton R. Young Power Plant Unit No. 1. Testing showed dra- matic improvement in cyclone combustion, improved slag tapping, and a 13% reduction in boiler air flow require- ments. to over 86% and the total gross heat rate improved by 123 Btu/kWh. In addition, boiler efficiency increased from 82% Commercial Applications Western SynCoal LLC owns the ACCP technology and is responsible for all activities related to commercialization. ACCP has the potential to enhance the use of low- rank western subbituminous and lignite coals. The Syn- Coal” is a viable compliance option for meeting SO, emission reduction requirements. SynCoal” is an ideal supplemental fuel for plants seeking to burn western low- rank coals because the ACCP allows a wider range of low-sulfur raw coals without derating the units. The participant has six long-term agreements in place to pro- vide SynCoal” to industrial and utility customers. The ACCP has the potential to convert inexpensive, low-sulfur low-rank coals into valuable carbon-based reducing agents for many metallurgical applications. Furthermore, SynCoal” enhances cement and lime produc- tion and provides a value-added bentonite product. Program Update 1999 5-137 Coal Processing for Clean Fuels Coal Preparation Technologies Development of the Coal Quality Expert™ Project completed. Participants ABB Combustion Engineering, Inc. and CQ Ine. Additional Team Members Black & Veatch—cofunder and software developer Electric Power Research Institute—cofunder The Babcock & Wilcox Company—cofunder and pilot-scale tester Electric Power Technologies, Inc.—field tester University of North Dakota, Energy and Environmental Research Center—bench-scale tester Utility Companies—{5 hosts) Locations Grand Forks, Grand Forks County, ND (bench tests) Windsor, Hartford County, CT (bench- and pilot-scale tests) Alliance, Columbiana County, OH (pilot-scale tests) Five utility host sites Technology CQ Inc.’s EPRI Coal Quality Expert™ (CQE™) computer software Plant Capacity/Production Full-scale testing took place at six utility sites ranging in size from 250 to 880 MWe. Coal Wide variety of coals and blends Coal Quality Expert, CQE, CQIS, and CQIM are trademarks of the Electric Power Research Institute. Pentium is a registered trademark of Intel. OS/2 is a registered trademark of IBM. Windows is a registered trademark of Microsoft Corporation. 5-138 Program Update 1999 SELECTED COALS CLEAN COAL ANTHRACITE LIGNITE SUBBITUMINOUS. BITUMINOUS | | 4 BENCH-SCALE TESTING PILOT-SCALE BOILER FULL-SCALE BOILER COMPUTER EXPERT MODEL Project Funding Total project cost $21,746,004 100% DOE 10,863,911 50 Participants 10,882,093 50 Project Objective The objective of the project was to provide the utility industry with a PC software program to confidently and inexpensively evaluate the potential for coal-cleaning, blending, and switching options to reduce emissions while producing the lowest cost electricity. Specifically the project was to (1) enhance the existing Coal Quality Information System (CQIS™) database and Coal Quality Impact Model (CQIM™) to allow assessment of the effects of coal-cleaning on specific boiler costs and per- formance, and (2) develop and validate CQE™, a model that allows accurate and detailed prediction of coal quality impacts on total power plant operating cost and performance. Technology/Project Description The CQE™ is a software tool that brings a new level of sophistication to fuel decisions by integrating the system- wide impact of fuel purchase decisions on coal-fired power plant performance, emissions, and power genera- tion costs. The impacts of coal quality; capital improve- ments; operational changes; and environmental compli- ance alternatives on power plant emissions, performance, and production costs can be evaluated using CQE™. CQE™ can be used to systematically evaluate all such impacts, or it may be used in modules with some default data to perform more strategic or comparative studies. Coal Processing for Clean Fuels Calendar Year 1988 1989 1990 1991 3 44/1 2 3 4/1 2 3 4/1 2 3 1992 1993 1994 1 2 3 4 1 2 3 4 1 2 3 4 1 1995 1996 Development 6/90| 8/90 12/88 Preaward DOE selected project (CCT-I) 12/9/88 NEPA process completed (MTF) 4/27/90 Operation initiated 8/90 Environmental monitoring plan completed 7/31/90 Operation Field testing completed 4/93 Cooperative agreement awarded 6/14/90 CQE Release 1.2 issued 12/97 Project completed/ final report issued 6/98 CQE Release 1.1 beta issued 6/96 CQE CD-ROM issued 12/95 _I Results Summary — Performance issues, and Environmental — Alternative emissions control strategies. * CQE™ includes models to evaluate emission and * Operates on an OS/2 Warp” (Version 3 or later) operat- regulatory issues. ing system with preferred hardware requirements of a Pentium® personal computer, | gigabyte hard disk Operational space, 32 megabytes RAM, 1024x768 SVGA, and * CQE™ can be used on a stand-alone computer or as a CD-ROM. network application for utilities, coal producers, and Economic equipment manufacturers to perform detailed coal . impact analyses. * CQE™ includes economic models to determine pro- . . duction cost components for coal-cleaning processes, * Four features included in the CQE™ program: ; . <5 power production equipment, and emissions control — Fuel Evaluator, systems. — Plant Engineer, — Environmental Planner, and — Coal-Cleaning Expert. * CQE™ can be used to evaluate: — Coal quality, — Transportation system options, Coal Processing for Clean Fuels Program Update 1999 5-139 Project Summary Background CQE™ began with EPRI’s CQIM™, developed for EPRI by Black & Veatch and introduced in 1989. CQIM™ was endowed with a variety of capabilities, including evaluat- ing Clean Air Act compliance strategies, evaluating bids on coal contracts, conducting test-burn planning and analysis, and providing technical and economic analyses of plant operating strategies. CQE™, which combines CQIM™ with other existing software and databases, extends the art of model-based fuel evaluation established by CQIM™ in three dimensions: new flexibility and application, advanced technical models and performance correlations, and advanced user interface and network awareness. Algorithm Development Data derived from bench-, pilot-, and full-scale testing were used to develop the CQE™ algorithms. Bench- scale testing was performed at ABB Combustion Engineering’s facilities in Windsor, Connecticut and the University of North Dakota’s Energy and Environmental Research Center in Grand Forks, North Dakota. Pilot- scale testing was performed at ABB Combustion Engineering’s facilities in Windsor, Connecticut and Alliance, Ohio. The five field test sites were: + Alabama Power’s Gatson, Unit No. 5 (880-MWe), Wilsonville, Alabama; * Mississippi Power’s Watson, Unit No. 4 (250-MWe), Gulfport, Mississippi; * New England Power’s Brayton Point, Unit No. 2 (285-MWe) and Unit No. 3 (615-MWe), Somerset, Massachusetts; * Northern States Power’s King Station (560-MWe), Bayport, Minnesota; and * Public Service Company of Oklahoma’s Northeastern, Unit No. 4 (445-MWe), Oologah, Oklahoma. 5-140 Program Update 1999 The six large-scale field tests consisted of burning a baseline coal and an alternate coal over a two month period. The baseline coal was used to characterize the operating performance of the boiler. The alternate coal, a blended or cleaned coal of improved quality, was burned in the boiler for the remaining test period. The baseline and alternate coals for each test site also were burned in bench- and pilot-scale facilities under similar conditions. The alternate coal was cleaned at CQ Inc. to determine what quality levels of clean coal can be produced economically and then transported to the bench- and pilot-scale facilities for testing. All data from bench-, pilot-, and full-scale facilities were evaluated and correlated to formulate algorithms used to develop the model. CQE™ Capability The OS/2"-based program evaluates coal quality, trans- portation system options, performance issues, and alterna- tive emissions control strategies for utility power plants. CQE™ is composed of technical tools to evaluate performance issues, environmental models to evaluate emissions and regulatory issues, and economic models to determine production cost components, including con- sumables (e.g., fuel, scrubber additives), waste disposal, operation and maintenance, replacement energy costs, and operational and maintenance costs for coal-cleaning processes, power production equipment, and emissions control systems. CQE™ has four main features: * Fuel Evaluator—Performs system-, plant-, or unit- level fuel quality, economic, and technical assess- ments. * Plant Engineer—Provides in-depth performance evalu- ations with a more focused scope than provided in the Fuel Evaluator. * Environmental Planner—Provides access to evaluation and presentation capabilities of the Acid Rain Advisor. * Coal-Cleaning Expert—Establishes the feasibility of cleaning a coal, determines cleaning processes, and predicts associated costs. Software Description CQE™ includes more than 100 algorithms based on the data generated in the six full-scale field test. CQE™’s design philosophy underscores the impor- tance of flexibility by modeling all important power plant equipment and systems and their performance in real- world situations. This level of sophistication allows new applications to be added by assembling a model of how objects interact. Updated information records can be readily shared among all affected users because CQE™ is network-aware, enabling users throughout an organization to share data and results. The CQE™ object-oriented design, coupled with an object database management system, allows different views into the same data. As a result, staff efficiency is enhanced when decisions are made. CQE™ also can be expanded without major revi- sions to the system. Object-oriented programming allows new objects to be added and old objects to be deleted or enhanced easily. For example, if modeling advancements are made with respect to predicting boiler ash deposition (ie., slagging and fouling), the internal calculations of the object that provides these predictions can be replaced or augmented. Other objects affected by ash deposition (e.g., ash collection and disposal systems, soot blower systems) do not need to be altered; thus, the integrity of the underlying system is maintained. System Requirements CQE™ currently uses the OS/2" operating system, but the developers are planning to migrate to a Windows"-based platform. CQE™ can operate in stand-alone mode on a single computer or on a network. Technical support is available from Black & Veatch for licensed users. Coal Processing for Clean Fuels Commercial Applications The CQE™ system is applicable to all electric power generation plants and large industrial/institutional boilers that burn pulverized coal. Potential users in- clude fuel suppliers, environmental organizations, government and regulatory institutions, and engineer- ing firms. International markets for CQE™ are being explored by both CQ Inc. and Black & Veatch. EPRI owns the software and distributes CQE™ to EPRI members for their use. CQE™ is available to others in the form of three types of licenses: user, consultant, and commercializer. CQ Inc. and Black & Veatch have each signed commercialization agree- ments, which give both companies non-exclusive worldwide rights to sell user’s licenses and to offer consulting services that include the use of CQE™ Two USS. utilities have been licensed to use copies of CQE™’s stand-alone Acid Rain Advisor. Over 30 U.S. utilities and one U.K. utility have CQE™ through their EPRI membership. Over 100 utilities and coal companies are now using CQE™. pending with several non-EPRI-member U.S. and for- software. Proposals are eign utilities to license their software. The CQE™ team has a Home Page on the World Wide Web (http://www. fuels.bv.com:80/cqe/cge.htm) and the EPRI Fuels Web Server to promote CQE™, facilitate communications between CQE™ developers and users, and eventually allow software updates to be distributed over the Internet. to provide an on-line updatable user’s manual. The It also was developed Home Page also helps attract the interest of interna- tional utilities and consulting firms. CQE™ was recognized by the Secretary of Energy and the President of EPRI in 1996 as the best of nine DOE/EPRI cost-shared utility research and develop- ment projects under the “Sustainable Electric Partner- ship” program. Coal Processing for Clean Fuels Contacts . Clark D. Harrison, President, (724) 479-3503 CQ Ine. ° 160 Quality Center Rd. Homer City, PA 15748 Douglas Archer, DOE/HQ, (301) 903-9443 Joseph B. Renk, NETL, (412) 386-6406 References Final Report: Development of a Coal Quality Expert. June 20, 1998. Harrison, Clark D., e¢ a/. “Recent Experience with the CQE™.” Fifth Annual Clean Coal Technology Con- ference: Technical Papers. January 1997. CQE™ Users Manual, CQE™ Home Page at http:// www.fuels.bv.com:80/cqge/cqe.htm. Comprehensive Report to Congress on the Clean Coal Technology Program: Development of the Coal Qual- ity Expert. ABB Combustion Engineering, Inc., and CQ Inc. Report No. DOE/FE-0174P. U.S. Depart- ment of Energy. May 1990. (Available from NTIS as DE90010381.) ACENTRAL AND SOUTH WEST COMPANY PRSo A SOUTHERN COMPANY 6 new England Power. 4 S0UTHERN company A NEES company 2 aes _— POWER Wiekieciees POWER A Utilities acted as hosts for field tests of CQE™. Program Update 1999 5-141 Coal Processing for Clean Fuels Mild Gasification ENCOAL® Mild Coal Gasification Project Project completed. Participant ENCOAL Corporation (a wholly owned subsidiary of Bluegrass Coal Development Company) Additional Team Members Bluegrass Coal Development Company (a wholly owned subsidiary of AEI Resources, Inc.}—cofunder SGI International—technology developer, owner, licensor Triton Coal Company (a wholly owned subsidiary of Vulcan Coal Company)— host Location Near Gillette, Campbell County, WY (Triton Coal Company’s Buckskin Mine site) Technology SGI International’s Liquids-From-Coal (LFC") process Coal Low-sulfur Powder River Basin (PRB) subbituminous coal, 0.45% sulfur Plant Capacity/Production 1,000 tons/day of subbituminous coal feed Project Funding Total project cost $90,664,000 100% DOE 45,332,000 50 Participant 45,332,000 50 Project Objective To demonstrate the integrated operation of a number of novel processing steps to produce two higher-heating value fuel forms from mild gasification of low-sulfur ENCOAL, LFC, CDL, and PDF are registered trademarks of SGI International and Bluegrass Coal Development Company. 5-142 Program Update 1999 + Le LIQUIDS mY CYCLONE COAL a wet FLUE GAS 7 f-\ DESULFURIZATION a LI & ee STACK RAW COAL Saray) DRYER FINES TO COMBUSTOR CYCLONE pryer' PROCESS-DERIVED FUEL STORAGE DRYER GAS PRODUCT GAS PYROLYZER PYROLYZER QUENCH COMBUSTOR FINES TO a AIR PROCESS-DERIVED FINISHER FUEL STORAGE DEACTIVATION [cooLeR TO PDF STORAGE | - ELECTROSTATIC PRECIPITATORS COAL- PROCESS GAS DERIVED ) Pree are uiquiD. || Basvee COAL-DERIVED LIQUID STORAGE p= aa BS. TO TRUCK AND RAIL LOADOUT subbituminous coal, and to provide sufficient products for potential end users to conduct burn tests. Technology/Project Description Coal is fed into a rotary grate dryer where it is heated to reduce moisture. The temperature is controlled so that no significant amounts of methane, CO,, or CO are released. The solids are then fed to the pyrolyzer where the tem- perature is about 1,000 °F, and all remaining water is removed. A chemical reaction releases the volatile gas- eous material. Solids exiting the pyrolyzer are quenched to stop the pyrolysis reactions. In the original process, the quench table solids were further cooled in a rotary cooler and transferred to a surge bin. A single 50% flow rate vibrating fluidized-bed (VFB) was added to stabilize the Process-Derived Fuel (PDF®) with respect to oxygen and water. In the VFB, the partially-cooled, pyrolyzed solids contact a gas stream containing a controlled amount of oxygen. Termed “oxi- dative deactivation,” a reaction occurs at active surface sites in the particles, reducing the tendency for spontaneous ignition. Following the VFB, the solids are cooled to near atmospheric temperature in an indirect rotary cooler where water is added to rehydrate the PDF®. A patented dust suppressant is added as the PDF® leaves the surge bin. The hot gas produced in the pyrolyzer is sent through a cyclone for removal of the particulates, and then cooled in a quench column to stop any additional pyrolysis reac- tions and to condense the Coal-Derived Liquid (CDL"*). Coal Processing for Clean Fuels Calendar Year 1994 1 2 3 4/1 2 3 4/1 2 3 4/1 1988 1989 1990 1991 3 4/1 2 3 4 1 £2 3 4 1 2 3 Preaward 12/89 9/90 DOE selected project (CCT-IIl) 12/19/89 Design and Construction 7/92 [bros initiated 7/92 Construction completed 6/92 Environmental monitoring plan completed 5/29/92 Preoperational tests initiated 4/92 Design completed 7/91 Ground breaking/construction started 10/26/90 Cooperative agreement awarded 9/17/90 NEPA process completed (EA) 8/1/90 Operation Operation completed 7/97 Project completed/final report issued 12/97 Results Summary Environmental The PDF® contains 0.36% sulfur with a heat content of 11,100 Btu/Ib (compared to 0.45% sulfur and 8,300 Btu/Ib for the feed coal). The CDL® contains 0.6% sulfur and 140,000 Btu/gal (compared to 0.8% sulfur and 150,000 Btu/gal for No. 6 fuel oil). In utility applications, PDF® enabled reduction in SO, emissions, reduction in NO, emissions (through flame stabilization), and maintenance of boiler rated capacity with fewer mills in service. LFC® products contained no toxins in concentrations anywhere close to federal limits. Operational Steady state operation exceeding 90% availability was achieved for extended periods for the entire plant (numerous runs exceeded 120 days duration). Coal Processing for Clean Fuels The LFC® process consistently produced 250 tons/day of PDF® and 250 barrels/day of CDL” from 500 tons/ day of run-of-mine PRB coal. Integrated operation of the LFC® process components over five years has provided a comprehensive database for evaluation and design of a commercial unit. Over 83,500 tons of PDF® were shipped via 17 unit trains and one truck shipment to seven customers in six states. Shipments included 100% PDF® and blends from 14-94% PDF®. PDF®, alone and in blends, demonstrated excellent combustion characteristics in utility applications, providing heating values comparable to bituminous coal, more reactivity than bituminous coal, and a stable flame. The low-volatile PDF® also showed promise as a re- ductant in direct iron reducing testing and also as a blast furnace injectant in place of coke. Nearly 5 million gallons of CDL” were produced and shipped to eight customers in seven states. CDL® demonstrated fuel properties similar to a low- sulfur No. 6 fuel oil but with the added benefit of lower sulfur content. High aromatic hydrocarbon content, however, may make CDL” more valuable as a chemical feedstock. Economic A commercial plant designed to process 15,000 metric-ton/day would cost an estimated $475,000,000 (2001$) to construct, with annual operating and main- tenance costs of $52,000,000 per year. Program Update 1999 5-143 Project Summary Operational Performance The LFC® facility operated for more than 15,000 hours over a five-year period. Steady-state operation was main- tained for much of the demonstration with availabilities of 90% for extended periods. The length of operation and volume of production proved the soundness and durabil- ity of the process. Exhibit 5-42 summarizes ENCOAL’s production history. By the end of the demonstration, over 83,500 tons of PDF” were shipped via 17 unit trains and one truck shipment to seven customers in six states. Ship- ments included 100% PDF® and blends from 14-94% PDF*. Over 5 million gallons of CDL® were produced and shipped to eight customers in seven states. PDF® Product. As with most demonstrations, how- ever, success required overcoming many challenges. The most difficult challenge had to do with stability of the PDF® product, which had to be resolved in order to achieve market acceptance. In June 1993, efforts ceased in trying to correct per- sistent PDF® stability problems within the bounds of the original plant design. The rotary cooler failed to provide the deactivation necessary to quell spontaneous ignition of PDF®. ENCOAL concluded that a separate, sealed vessel was needed for product deactivation. A search for a suitable design led to adoption of a VFB. A 500-ton/ day VFB was installed between the quench table and rotary cooler. (Installation of a second 500 ton/day VFB was planned but never implemented.) Although the VFB enhanced deactivation, the PDF still required “finishing” to achieve stabilization. Exten- sive study revealed that more oxygen was needed for deactivation. Two courses of action were pursued: (1) development of interim measures to finish deactiva- tion external to the plant, enabling immediate PDF® ship- ment for test burns; and (2) development of an in-plant process for finishing, eliminating product quality and labor penalties for external finishing. 5-144 — Program Update 1999 “Pile layering” was the primary external PDF® finish- ing measure adopted. However, PDF® quality becomes somewhat impaired by impacting size, moisture and ash content. Pursuit of a finishing process step resulted in estab- lishment of a stabilization task force composed of private sector and government engineers and scientists. The outcome was construction and testing of a Pilot Air Stabi- lization System (PASS) to complete the oxidative deacti- vation of PDF". The PASS controls temperature and humidity during forced oxidation. The data obtained were used to develop specifications and design require- ments for a full-scale, in-plant PDF® finishing unit based upon a commercial (Aeroglide) tower dryer design. CDL® Product. The first shipment of ENCOAL’s liquid product experienced unloading problems. The use of heat tracing and tank heating coils solved the unload- ing problems for subsequent customers. The CDL” also contained more solids and water than had been hoped for, but was considered usable as a lower grade oil. Following VFB installation, CDL* quality improved. The pour point ranged from 75—95 °F, and the flash point averaged 230 °F, both within the design range. Water content was down to 1-2%, and solids content was 24%. Improvements resulted from more consistent operation and lower pyrolysis temperatures and higher pyrolysis flow rates enabled by a new pyrolyzer water seal. Environmental Performance PDF® Product. PDF” offers the advantages of low-sulfur Powder River Basin coal without a heating value penalty. In fact, the LFC® process removes organically-bound sulfur, making the PDF® product lower in sulfur than the parent coal on a Btu basis. Because the ROM coal is low in ash, PDF® ash levels remain reasonable after process- ing, even though the ash level is essentially doubled (ash from one ton of ROM coal goes into one-half ton of PDF®). Dust emissions were not a problem with PDF®. A dust suppressant (MK) was sprayed on the PDF*® to coat the surface as it leaves the storage bin. Also, PDF” has a narrower particle size distribution than ROM coal, having a larger fines content but fewer particles in the fugitive dust range than ROM coal. Exhibit 5-42 ENCOAL Production Pre-VFB Post-VFB 1992 1993 1994 1995 1996 1997' Sum Raw Coal Feed (tons) 5,200 12,400 67,500 65,800 68,000 39,340 258,300 PDF® Produced (tons) 2,200 4,900 31,700 28,600 33,300 19,300 120,500 PDF” Sold (tons) 0 0 23,700 19,100 32,700 7,400 82,900 CDL* Produced (bbl) 2,600 6,600 28,000 31,700 32,500 20,300 121,700 Hours on Line 314 980 4,300 3,400 3,600 2,603 15,197 Average Length of Runs (Days) 2 8 26 38 44 75 'Through June 1997. Coal Processing for Clean Fuels ENCOAL/’s test burn shipments became international when Japan’s Electric Power Development Company (EPDC) evaluated six metric tons of PDF® in 1994. The EPDC, which must approve all fuels being considered for electric power generation in Japan, found PDF® accept- able for use in Japanese utility boilers. In October 1996, instrumented combustion testing was conducted at the Indiana-Kentucky Electric Co- operative’s (IKEC) Clifty Creek Station, Unit #3. Impor- tant findings included the following: * Full generating capacity using PDF® was possible with one mill out of service, which was not possible on the baseline fuel. Operation on PDF" afforded time to perform mill maintenance and calibration without losing capacity or revenues, increasing capacity factor and availability, and decreasing operating and mainte- nance costs. * NO, emissions were reduced by 20% due to high PDF* reactivity, resulting in almost immediate ignition upon leaving the burner coal nozzle. Furthermore, PDF® sustained effective combustion (maintaining low loss on ignition) with very low excess oxygen, which is conducive to low NO, emissions. * PDF* use precipitated increased ash deposits in the convective pass that were wetter than those resulting from baseline coal use, requiring increased sootblow- ing to control build-up. CDL® Product. The CDL” liquid product is a low-sulfur, highly aromatic, heavy liquid hydrocarbon. CDL* fuel characteristics are similar to a low-sulfur No. 6 fuel oil, except that the sulfur content is significantly less. CDL*’s market potential as a straight industrial residual fuel, however, appears limited. The market for CDL” as a fuel never materialized and CDL" has limited application as a blend for high-sulfur residual fuels due to incompat- ibility of the aromatic CDL® with many straight-chain hydrocarbon distillates. Coal Processing for Clean Fuels ENCOAL determined that a centrifuge was needed to reduce solids retention and improve marketability of CDL* (tests validated a 90% removal capability); and an optimum slate of upgraded products was identified. The upgraded products were: (1) crude cresylic acid, (2) pitch, (3) refinery feedstock (low-oxygen middle distillate), and (4) oxygenated middle distillate (industrial fuel). Economic The “base case” for economics of a commercial plant is the 15,000-metric-ton/day, three-unit North Rochelle LFC* plant, the commercial-scale plant proposed by ENCOAL, with an independent 80-MWe cogeneration unit, and no synthetic fuel tax credit (29c tax credit). It is assumed that the cogeneration unit is owned and operated by an independent third-party. The capital cost for a full- scale three module LFC* plant is $475 million. Economic benefits from an LFC* commercial plant are derived from the margin in value between a raw, unprocessed coal and the upgraded products, making an LFC® plant dependent on the cost of feed coal. In fact, this is the largest single operating cost item. The total estimated operating cost is $9.00/ton of feed coal includ- ing the cost of feed coal, chemical supplies, maintenance, and labor. Commercial Applications In a commercial application, CDL® would be upgraded to cresylic acid, pitch, refinery feedstock, and oxygenated middle distillate. Oxygenated middle distillate, the low- est value by-product, would be used in lieu of natural gas as a make-up fuel for the process (30% of the process heat input). PDF® would be marketed not only as a boiler fuel but as a supplement or substitute for coke in the steel industry. PDF" characteristics make it attractive to the metallurgical market as a coke supplement in pulverized coal injection and granular coal injection methods, and as a reductant in direct reduced iron processes. Partners in the ENCOAL® project completed five detailed commercial feasibility studies over the course of the demonstration and shortly thereafter—two Indone- sian, one Russian, and two U.S. projects. A U.S. project has received an Industrial Siting Permit and an Air Qual- ity Construction Permit, but the project is on hold due to lack of funding. Contacts James P. Frederick SGI International P.O. Box 3038 Gillette, WY 82717 (307) 686-2894 (fax) Douglas Archer, DOE/HQ, (301) 903-9443 Douglas M. Jewell, NETL, (304) 285-4720 References * ENCOAL*® Mild Gasification Plant Commercial Plant Feasibility Study. U.S. Department of Energy. Sep- tember 1997. Report No. DOE/MC/27339. (Available from NTIS as DE98002005.) * Final Design Modifications Report. U.S. Department of Energy. September 1997. Report No. DOE/MC/ 27339-5797. (Available from NTIS as DE98002006.) *« ENCOAL* Mild Gasification Project: ENCOAL Project Final Report. Report No. DOE/MC/27339- 5798. U.S. Department of Energy. September 1997. (Available from NTIS as DE98002007.) ¢ Johnson, S.A., and Knottnerus, B.A. “Results of the PDF* Test Burn at Clifty Creek Station.” U.S. Depart- ment of Energy Topical Report. October 1996. * ENCOAL* Mild Coal Gasification Demonstration Project Public Design and Construction Report. Re- port No. DOE/MC/27339-4065. ENCOAL Corpora- tion. December 1994. (Available from NTIS as DE95009711.) Program Update 1999 5-145 Industrial Applications Industrial Applications Program Update 1999 5-147 Industrial Applications Clean Power from Integrated Coal/Ore Reduction (CPICOR™) Participant CPICOR™ Management Company L.L.C. (a limited liability company composed of subsidiaries of the Geneva Steel Company) Additional Team Members Geneva Steel Company—cofunder, constructor, host, and operator of unit Location Vineyard, Utah County, UT (Geneva Steel Co.’s mill) Technology HIsmelt® direct iron making process Plant Capacity/Production 3,300 tons/day liquid iron production Coal Bituminous, 0.5% sulfur Project Funding Total project cost $1,065,805,000 100% DOE 149,469,242 14 Participant 916,335,758 86 Project Objective To demonstrate the integration of direct iron making with the coproduction of electricity using various U.S. coals in an efficient and environmentally responsible manner. Technology/Project Description The HIsmelt® process is based on producing hot metal and slag from iron ore fines and non-coking coals. The heart of the process is producing sufficient heat and main- HIsmelt is a registered trademark of HIsmelt Corporation Pty Limited. CPICOR is a trademark of the CPICOR™ Management Company, L.L.C. 5-148 — Program Update 1999 HOT BLAST : POST-COMBUSTION ZONE COAL, IRON ORE, COAL, AND FLUXES IRON ORE, AND FLUXES J FUEL GAS GAS CLEANING SLAG a) HOTMETAIS “veocon VESSEL OXYGEN STOVES oo ~ COLD BLAST taining high heat transfer efficiency in the post-combus- tion zone above the reaction zone, to reduce and smelt iron oxides. Tests have demonstrated 60% post-combus- tion levels (degree of post-combustion attained) with 90% heat transfer efficiency. The HIsmelt® process uses a vertical smelt reduction reactor, which is a closed molten bath vessel, into which iron ore fines, coal, and fluxes are injected. The coal is injected into the bath where carbon is dissolved rapidly. The carbon reacts with oxygen (from the iron ore) to form CO and metallic iron. Injection gases and evolved CO entrain and propel droplets of slag and molten iron up- ward into the post-combustion zone. The iron reduction reaction in the molten bath is endothermic; therefore, additional heat is needed to sus- tain the process and maintain hot metal temperature. This heat is generated by post-combusting the CO and hydrogen from the bath with an O,-enriched hot air blast from the central top lance. The heat is absorbed by the slag and molton iron droplets and returned to the bath by gravity. Droplets in contact with the gas in the post-combustion zone absorb heat, but are shrouded during the descent by ascending reducing gases (CO), which, together with bath carbon, prevent unacceptable levels of FeO in the slag. The molten iron collects in the bottom of the bath and is continuously tapped from the reactor through a fore- hearth, which maintains a constant level of iron in the reactor. Slag, which is periodically tapped through a conventional blast furnace-type tap hole, is used to coat and control the internal cooling system and reduce the heat loss. Industrial Applications Calendar Year ** te 1993 1997 4/1 2 3 4/1 2 2000 2001 2002 3 94/1 2 3 4/1 2003 2004 2005 2006 2 3 4/1 2 3 4 1 2 3 4 12 | Preaward DOE selected project (CCT-V) 5/4/93 Design and Construction | NEPA process completed 12/00* Construction started 12/00* Cooperative agreement awarded 10/11/96 Environmental monitoring plan completed 9/02* 10/05 Project completed/final report issued 10/05* Operation completed 10/05* 5/03 Operation Operation initiated 5/03* Construction completed 5/03* *Projected date “Years omitted Reacted gases, mainly N,, CO,, CO, H,, and H,O, exit the vessel. After scrubbing the reacted gases, the cleaned gases will be combusted to produce 170 MWe of power. The cleaned gases can also be used to pre-heat and partially reduce the incoming iron ore. Project Status/Accomplishments The cooperative agreement was awarded on October 11, 1996. CPICOR™ analyzed the global assortment of new direct ironmaking technologies to determine which tech- nology would be most adaptable to western U.S. coals and raw materials. Originally, the COREX" process appeared suitable for using Geneva’s local raw materials; however, lack of COREX" plant data on 100% raw coals and ores prevented its application in this demonstration. Thus, CPICOR™ chose to examine alternatives. The processes evaluated included: AISI direct ironmaking, DIOS, Romelt, Tecnored, Cyclonic Smelter, and HIsmelt®. The HIsmelt® process appears to offer good economic and operational potential, as well as the pros- pect of rapid commercialization. CPICOR™ has com- Industrial Applications pleted testing of two U.S. coals at the HIsmelt® pilot plant near Perth, Australia. On February 1, 1999, Geneva Steel Company (CPICOR™ Management Company’s parent corporation) filed a voluntary petition for bankruptcy under Chapter 11 of the United States Bankruptcy Code in the U.S. Bank- ruptcy Court for the District of Utah. Geneva Steel intends to emerge from Chapter 11 with a restructured balance sheet that will enable full participation in this demonstra- tion project. Other developments include the following: DOE is reviewing final drafts of license and marketing agreements between HIsmelt® and CPICOR™; DOE has established a NEPA Team to review the Environmental Information Volume and begin the NEPA scoping pro- cess; and baseline air monitoring is in progress. Commercial Applications The HIsmelt® technology is a direct replacement for exist- ing blast furnace and coke-making facilities with addi- tional potential to produce steam for power production. Of the existing 79 coke oven batteries, half are 30 years of age or older and are due for replacement or major rebuilds. There are about 60 U.S. blast furnaces, all of which have been operating for more than 10 years, with some originally installed up to 90 years ago. HIsmelt® represents a viable option as a substitute for conventional iron making technology. The HIsmelt® process is ready for demonstration. Two pilot plants have been built, one in Germany in 1984 and one in Kwinana, Western Australia in 1991. Through test work in Australia, the process has been proven— operational control parameters have been identified and complete computer models have been successfully devel- oped and proven. The goal is to have a fully operational commercial plant by early next decade. Program Update 1999 5-149 Industrial Applications Pulse Combustor Design Qualification Test Participant ThermoChem, Inc. Additional Team Member Manufacturing and Technology Conversion International, Inc. (MTCI)—technology supplier Location Baltimore, MD (MTCI Test Facility) Technology MTCI’s Pulsed Enhanced™ Steam Reforming using a multiple resonance tube pulse combustor. Plant Capacity/Production 30 million Btu/hr (steam reformer) Coal Black Thunder (Powder River Basin) subbituminous Project Funding Total project cost $8,612,054 100% DOE 4,306,027 50 Participants 4,306,027 50 Project Objective To demonstrate the operational/commercial viability of a single 253-resonance-tube pulse combustor unit and evaluate characteristics of coal-derived fuel gas generated by an existing Process Development Unit (PDU). Technology/Project Description MTCI’s Pulsed Enhanced™ Steam Reforming process incorporates an indirect heating process for thermochemi- cal steam gasification of coal to produce hydrogen-rich, clean, medium-Btu content fuel gas without the need for an oxygen plant. Indirect heat transfer is provided by immersing multiple resonance-tube pulse combustors in a PulseEnhanced is a trademark of MTCI. 5-150 Program Update 1999 VENTURI STACK VENT GAS COOLING STEAM mal 253-TUBE open PULSED HEATER | HEATER = po Ss FLUE GAS FEED : WATER (FOR START-UP) FUEL : ue GAS FUEL GAS fluidized-bed steam gasification reactor. Pulse combus- tion increases the heat transfer rate by a factor of 3 to 5, thus greatly reducing the heat transfer area required in the gasifier. The pulse combustor represents the core of the PulsedEnhanced™ Steam Reforming process because it provides a highly efficient and cost-effective heat source. Demonstration of the combustor at the 253-resonance- tube commercial-scale is critical to market entry. The 253-resonance-tube unit represents a 3.5 scale-up from previous tests. Testing will seek to verify scale-up criteria and appropriateness of controls and instrumentation. Also, an existing PDU will be used to gasify coal feed- stock to provide fuel gas data, including energy content, species concentration, and yield. Char from the PDU will be evaluated as well. The facility will also have a product gas cleanup train that includes two stages of cyclones, a venturi scrubber with a scrubber tank, and a gas quench column. An air- cooled heat exchanger will be used to reject heat from the condensation of excess steam (unreacted fluidization steam) quenched in the venturi scrubber and gas quench column. All project testing will be performed at the MTCI test facility in Baltimore, Maryland. Industrial Applications [ ca alendar Year 1991 1994 1995 4q\eeerte ae en Ore ieee eee 1998 1999 2001 24344 Hl oitettotts 4-203. 4 aatte. 1 I DOE selected Cooperative agreement project (CCT-IV) awarded 10/27/92 9/12/91 Design and Construction I Project relocation requested 10/26/94 Restructuring complete 3/21/98 4/00 7/00 | Final report 7/00* Operation complete 6/00* Operation initiated 04/00* PDU Gasification data 4/00* Design complete 2/15/99 Revised Cooperative Agreement Awarded 9/29/98 *Projected Date Project Status/Accomplishments On September 10, 1998, DOE approved revision of ThermoChem, Inc.’s Cooperative Agreement for a scaled-down project. The original project, awarded in October 1992, was a commercial demonstration facility that would employ 10 identical 253-resonance-tube pulse combustor units. After fabrication of the first combustor unit, the project went through restructuring. The revised project will demonstrate a single 253-reso- nance-tube pulse combustor. NEPA requirements were satisfied on November 30, 1998, with a Categorical Exclusion. The first major milestone was completion of the design on February 15, 1999. Construction of the combustor unit is scheduled to be completed in March 2000, with operations begin- ning in April 2000. The mild coal gasification data will be collected in April 2000 using the existing PDU. Industrial Applications Commercial Applications PulsedEnhanced™ Steam Reforming has application in many different processes. Coal, with the world production on the order of four billion tons per year, constitutes the largest potential feedstock for steam reforming. Other potential feedstocks include spent liquor from pulp and paper mills, refuse-derived fuel, municipal solid waste, sewage sludge, biomass, and other wastes. Although the project will demonstrate mild gasifica- tion only, the following coal-based applications are envisioned: * Coal processing for combined-cycle power generation, * Coal processing for fuel cell power generation, * Coal pond waste and coal rejects processing to produce a hydrogen-rich gas from the steam reformer for use in overfiring or reburning to reduce NO, emissions, Coal processing for production of gas or liquid fuel, and char for the steel industry for use in direct reduc- tion of iron ore, Coal processing for producing compliance fuels, Mild gasification of coal, Co-processing of coal and wastes, and Coal drying. In addition, the technology has application for black liquor processing and chemical recovery and for hazardous, low-level radioactive, and low-level mixed waste volume reduction and destruction. Program Update 1999 5-151 Industrial Applications Blast Furnace Granular-Coal Injection System Demonstration Project Project completed. Participant Bethlehem Steel Corporation Additional Team Members British Steel Consultants Overseas Services, Inc. (marketing arm of British Steel Corporation)— technology owner CPC-Macawber, Ltd. (formerly named Simon-Macawber, Ltd.)—equipment supplier Fluor Daniel, Inc.—architect and engineer ATSI, Inc.—injection equipment engineer (North America technology licensee) Location Burns Harbor, Porter County, IN (Bethlehem Steel’s Burns Harbor Plant, Blast Furnace Units C and D) Technology British Steel and CPC-Macawber blast furnace granular- coal injection (BFGCI) process Plant Capacity/Production 7,000 net tons of hot metal (NTHM)/day (each blast furnace) Coal Eastern bituminous, 0.8—2.8% sulfur Western subbituminous, 0.4-0.9% sulfur Project Funding Total project cost $194,301,790 100% DOE 31,824,118 16 Participant 162,477,672 84 5-152 Program Update 1999 BLAST FURNACE MOLTEN SLAG IRON ORE h COKE HOT LOW-BTU LIMESTONE FURNACE GAS '@ COAL PREPARATION GRANULATED OFFGAS PREHEATER PARTICULATE REMOVAL, WET SCRUBBER CLEANED LOW-BTU oe BLAST FURNACE BLAST AIR CA OGS PLANT USE + BLAST FURNACE OFFGAS MOLTEN TO STEELMAKING Project Objective To demonstrate that existing iron making blast furnaces can be retrofitted with blast furnace granular-coal injec- tion technology; to demonstrate sustained operation with a variety of coal types, particle sizes, and injection rates; and to assess the interactive nature of these parameters. Technology/Project Description In the BFGCI process, either granular or pulverized coal is injected into the blast furnace in place of natural gas or oil as a blast furnace fuel supplement. The coal, along with heated air, is blown into the barrel-shaped section in the lower part of the blast furnace through passages called tuyeres, which creates swept zones in the furnace called raceways. The size of a raceway is important and is de- pendent upon many factors, including temperature. Low- ering of a raceway temperature, which can occur with natural gas injection, reduces blast furnace production rates. Coal, with a lower hydrogen content than either natural gas or oil, does not cause as severe a reduction in raceway temperatures. In addition to displacing natural gas, the coal injected through the tuyeres displaces coke, the primary blast furnace fuel and reductant (reducing agent), on approximately a pound-for-pound basis up to 40% of total requirements. Emissions generated by the blast furnace itself remain virtually unchanged by the injected coal; the gas exiting the blast furnace is cleaned and used in the mill. Sulfur from the coal is removed by the limestone flux and bound up in the slag, which is a salable by-product. Two high-capacity blast furnaces, Units C and D at Bethlehem Steel’s Burns Harbor Plant, were retrofitted with BFGCI technology. Each unit has a production capacity of 7,200 NTHM/day. The two units use about 2,800 tons/day of coal during full load operation. Industrial Applications Calendar Year ae 1989 1990 1991 1993 1994 1995 1996 SA SIS 2ST ATA SH 4 M2n SH 4a teu aa ira tls ae (i 12/89 11/90 11/95 Design and Construction Preaward A [ f Operation initiated 11/95 Preoperational tests initiated 2/95 DOE selected Construction completed 1/95 project (CCT-III) 12/19/89 Design completed 12/93 Construction started 9/93 NEPA process completed (EA) 6/8/93 Cooperative agreement awarded 11/26/90 Environmental monitoring plan completed 12/23/94 Operation Operation completed 11/98 Final report issued 10/99* Project completed 11/99* *Projected date “*Years omitted Results Summary Environmental * The BFGCI technology has the potential to reduce pollutant emissions substantially by displacing coke, the production of which results in significant emis- sions of air toxics. Operational * The low-ash, low-volatile, high-carbon coal provided a high coke replacement value. * Reliability of the coal system enabled the operators to reduce furnace coke to a low rate of 661 Ib/NTHM (pre-demonstration rate was 740 Ib/NTHM). + During the base period, permeability of the carbon layer in the blast furnace burden column (a critical parameter) indicated overall acceptable operation using low-ash, low-volatile, high-carbon coal. Industrial Applications Granular coals are easier to handle in pneumatic con- veying systems than pulverized coal because granular coals are not as likely to stick to conveying pipes if moisture control is not adequately maintained. Any decrease in furnace permeability as a result of coal injection can be minimized by increasing oxygen enrichment and raising moisture additions to the blast furnace. Higher ash coal had no adverse effect on furnace permeability. The productivity rate of the furnace was not affected by the 2.4 percentage point increase in coal ash at an injection rate of 260 Ilb/NTHM. There is a coke rate disadvantage of 3 b/NTHM for each | percentage point increase of ash in the coal at an injection rate of 260 Ib/NTHM. Hot metal quality was not affected by the increased ash content of the injection coal. Economic * The capital cost for one complete injection system at Burns Harbor was $15,073,106 (19908) for the 7,200 NTHM day blast furnace. * The total fixed costs (labor and repair costs) at Burns Harbor were $6.25/ton of coal. The total variable costs (water, electricity, natural gas, and nitrogen) were $3.56/ton of coal. Coal costs were $50-60/ton. * Ata total cost of $60/ton and a natural gas cost of $2.85/10° Btu, the iron cost savings would be about $6.50/ton of iron produced. * Based on the Burns Harbor production of 5.2 million tons of iron per year, the annual savings is about $34 million/yr. Program Update 1999 5-153 Project Summary Two high-capacity blast furnaces, Units C and D at Beth- lehem Steel’s Burns Harbor Plant, were retrofitted with BFGCI technology. Each unit has a production capacity of 7,000 NTHM/day. The two units use about 2,800 tons/ day of coal during full operation. This project represents the first U.S. blast furnace designed to deliver granular (coarse) coal. All previous blast furnaces have been de- signed to deliver pulverized (fine) coal. The project also represents about a 100% scale-up from CPC-Macawber’s Scunthorpe Works in England where the technology was developed. In addition to testing the technology on large, high- production blast furnaces, Bethlehem Steel conducted testing on different types of U.S. coal to determine the effect on blast furnace performance. Tests included east- ern bituminous coals with sulfur contents of 0.8—2.8% and western subbituminous coals having 0.4-0.9% sulfur. Specifically, the objective of the test program was to deter- mine the effect of coal grind and coal type on blast furnace performance. Other trials include determining the effects of coal types and coal chemistry on furnace performance. To date, results of two trials have been reported—a base period using low-ash, low-volatile coal and a trial period using high-ash, low-volatile coal. Operational Summary Virginia Pocahantas and Buchanan, a chemically similar coal from the same seam, but from a different mine, were used all of 1996. During the entire month of October 1996, the Burns Harbor C blast furnace operated without interruption using Virginia Pocahantas. This low-ash, low-volatile, high-carbon coal provided a high coke re- placement value for the base period test. The coal feed rate varied from 246-278 Ib/NTHM on a daily basis for an average feed rate of 264 Ib/NTHM. The furnace coke rate during the period averaged 661 Ib/NTHM. The granular coal injected in C furnace was about 15% minus 200 mesh for the month. 5-154 Program Update 1999 The injected coal rate of 264 Ib/NTHM is one of the highest achieved since startup of the coal facility. Reli- ability of the coal system enabled the operators to reduce furnace coke to a low rate of 661 Ib/NTHM. This low coke rate is not only economically beneficial, it is an indicator of the efficiency of furnace operation with regard to displacing coke with injected coal. Hot metal chemistry, particularly silicon and sulfur content, is an important iron making parameter. Specific silicon and sulfur values with low variability are vital to meeting steel-making specifications. The average values and standard deviations for silicon and sulfur can be seen in Exhibit 5-43. These values are compared to typical operation data on natural gas collected in January 1995. Exhibit 5-43 also shows the significant operating changes that occur with the use of injected coal versus natural gas. The wind volume on the furnace decreased significantly with the use of coal. Oxygen enrichment increased from 24.4% to 27.3% with coal. The amount of moisture added to the furnace in the form of steam signifi- cantly increased from 3.7 grains/SCF to 19.8 grains/SCF. All of these variables were increased by operating person- nel to maintain adequate burden material movement. These actions also increased the permeability of the fur- nace burden column, which is a function of the blast rate and the pressure drop through the furnace. The larger the permeability value, the better the furnace burden move- ment and the better the reducing gas flow rate through the furnace column. During the base period, the permeability indicated overall acceptable operation using low-ash, low-volatile, high-carbon coal. The next series of tests involved using a higher ash coal. In order to ensure that other variables did not influ- ence the test results, Buchanan coal was used, but the ash content was increased by eliminating one of the usual coal cleaning steps. The ash content of the coal used for the high-ash trial was 7.70% compared to 5.30% for the base period trial and the 4.72% for the period immedi- ately prior to the high-ash coal trial. As during the base trial period, the granular coal was about 15% minus 200 mesh. To ensure comparable results, Bethlehem Steel operators maintained consistent operation with the base period trials. A comparison of the high-ash trial to the base period is also contained in Exhibit 5-43. The amount of injected coal, general blast conditions, wind volume, blast pressure, top pressure, and moisture additions were comparable during the two trials. The primary change in operation, as expected, was the increase in the blast furnace slag volume. With the higher ash coal, the 461 Ib/NTHM slag volume was 8.7% higher than the baseline period of 424 Ilb/NTHM. The general conclusion is that higher ash content in the in- jected coal can be adjusted by the furnace operators and does not adversely affect overall furnace operations. However, the results lead to the conclusion that a 2.4 percentage point increase in injected coal ash results in a 8 Ib/NTHM increase in the furnace coke rate after correct- ing for other variables. This is the amount of coke carbon needed to replace the lower carbon in the higher-ash coal without an additional process penalty. Environmental Summary The greatest environmental benefit to the BFGCI is dis- placement of coke in favor of coal. Coke is essentially replaced on a pound-for-pound basis with granulated coal, up to 40% of the total requirements. The BFGCI technol- ogy has the potential to reduce pollutant emissions be- cause coke production results in significant emissions of air toxics. Economic Summary Capital cost for one complete injection system at Burners Harbor was approximately $15 million (1990$). This does not include infrastructure improvements, which cost $87 million at Burns Harbor. The fixed operating costs, which includes labor and repair costs, were $6.25/ton of coal. The variable operating costs, which include water, electricity, natural gas, and nitrogen, were $3.56/ton of Industrial Applications Exhibit 5-43 BFGCI Test Results Pre-Demonstration Base January 1995 October 1996 High Ash Test May 28 — June 23, 1997 Production, NTHM/day delays Coke Rate, Ibs/NTHM Rep. Natural Gas Rate, Ibs/NTHM Injected Coal Rate, Ibs/NTHM Total Fuel Rate, Ibs/NTHM Blast Conditions: Dry Air, SCFM Blast Pressure, psig Permeability Oxygen in wind, % Temp, F Moisture, grains/SCF Coke: H,O, % Hot Metal %: Silicon (Standard Dev.) Sulfur (Standard Dev.) Phos. Mn. Temp. F Slag %: SiO, ALO, CaO Volume, Ibs/NTHM 7,436 6,943 740 661 141 0 0 264 881 925 167,381 137,005 38.9 38.8 1.57 1.19 24.4 273 2,067 2,067 3.7 19.8 4.8 5.0 0.44 (.091) 0.50 (.128) 0.043 (.012) 0.040 (.014) 0.070 0.072 0.40 0.43 2,745 2,734 38.02 36.54 8.82 9.63 37.28 39.03 12.02 11.62 0.45 0.46 0.85 1.39 1.05 1.10 1.30 1.39 394 424 7,437 674 5.0 262 940 135,370 38.3 1.23 28.6 2,012 20.7 5.0 0.49 (0.97) 0.035 (.012) 0.073 0.46 2,733 36.21 9.91 39.40 11.32 0.45 1.40 1.10 1.40 461 Industrial Applications coal. Coal costs were $50-60/ton. This brought the total operating costs to $59.81—69.81/ton of coal. Using $60/ton of coal and a natural gas cost of $.88/10° Btu, the cost savings would be about $6.50/ton of iron produced. At Burns Harbor, which produces 5.2 million tons of iron per year, the savings would be about $34 million/yr. At Burners Harbor, the payback period is 3.44 years using a simple rate of return calculation. Commercial Applications BFGCI technology can be applied to essentially all U.S. blast furnaces. The technology should be applicable to any rank coal commercially available in the U.S. that has a moisture content no higher than 10%. The environmen- tal impacts of commercial application are primarily indi- rect and consist of a significant reduction of emissions resulting from diminished coke-making requirements. The BFGCI technology was developed jointly by British Steel and Simon-Macawber (now CPC-Macawber). British Steel has granted exclusive rights to market BFGCI tech- nology worldwide to CPC-Macawber. CPC-Macawber also has the right to sublicense BFGCI rights to other organizations throughout the world. CPC-Macawber has also recently installed a similar facility at United States Steel Corporation’s Fairfield blast furnace. Contacts Robert Bouman, (610) 694-6792 Bethlehem Steel Corporation Building C, Room 211 Homer Research Laboratory Mountain Top Campus Bethlehem, PA 18016 (610) 694-2981 (fax) Douglas Archer, DOE/HQ, (301) 903-9443 Leo E. Makovsky, NETL, (412) 386-5814 References Hill, D.G. et al. “Blast Furnace Granular-Coal Injection System Demonstration Project.” Sixth Clean Coal Con- ference Proceedings: Volume II - Technical Papers. April-May, 1998. Program Update 1999 5-155 Industrial Applications Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Project completed. Participant Coal Tech Corporation Additional Team Members Commonwealth of Pennsylvania, Energy Development Authority—cofunder Pennsylvania Power and Light Company—supplier of test coals Tampella Power Corporation—host Location Williamsport, Lycoming County, PA (Tampella Power Corporation’s boiler manufacturing plant) Technology Coal Tech’s advanced, air-cooled, slagging combustor Plant Capacity/Production 23 x 10° Btu/hr of steam Coal Pennsylvania bituminous, |.0—3.3% sulfur Project Funding Total project cost $984,394 100% DOE 490,149 50 Participant 494,245 50 Project Objective To demonstrate that an advanced cyclone combustor can be retrofitted to an industrial boiler and that it can simul- taneously remove up to 90% of the SO, and 90-95% of the ash within the combustor and reduce NO, to 100 ppm. 5-156 Program Update 1999 AIR-COOLED CERAMIC LINER, PRIMARY AIR, COAL, | AND SORBENT . START-UP SECONDARY AIR TERTIARY AIR SLAG Technology/Project Description Coal Tech’s horizontal cyclone combustor is internally lined with an air-cooled ceramic. Pulverized coal, air, and sorbent are injected tangentially toward the wall through tubes in the annular region of the combustor to cause cyclonic action. In this manner, coal-particle combustion takes place in a swirling flame in a region favorable to particle retention in the combustor. Secondary air is used to adjust the overall combustor stoichiometry. Tertiary air is injected at the combustor/boiler interface. The ceramic liner is cooled by the secondary air and maintained at a temperature high enough to keep the slag in a liquid, free- flowing state. The secondary air is preheated by the com- bustor walls to attain efficient combustion of the coal particles in the fuel-rich combustor. Fine coal pulveriza- tion allows combustion of most of the coal particles near the cyclone wall. The combustor was designed to retain a high percentage of the ash and sorbent fed to the combus- tor as slag. For NO, control, the combustor is operated fuel rich, with final combustion taking place in the boiler furnace to which the combustor is attached. SO, is cap- tured by injection of limestone into the combustor. The cyclonic action inside the combustor forces the coal ash and sorbent to the walls where it can be collected as liquid slag. Under optimum operating conditions, the slag con- tains a significant fraction of vitrified coal sulfur. Down- stream sorbent injection into the boiler provides additional sulfur removal capacity. In Coal Tech’s demonstration, an advanced, air- cooled cyclone coal combustor was retrofitted to a 23 x 10° Btu/hr, oil-designed package boiler located at the Tampella Power Corporation boiler factory in Williamsport, Pennsylvania. Industrial Applications Calendar Year 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 3 441 2 3 4/1 2 3 44/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4/1 2 3 4) 1 2 Design and Construction 7/86 3/87 11/87 9/91 Preaward Operation | Operation Construction completed 11/87 completed 5/90 Operation initiated 11/87 Environmental monitoring plan completed 9/22/87 Project completed/final report issued 9/91 Design completed 7/87 Ground breaking/construction started 7/87 Cooperative agreement awarded 3/20/87 NEPA process completed (MTF) 3/26/87 DOE selected project (CCT-I) 7/24/86 Results Summary * Ash/sorbent retention in the combustor as slag aver- Economic Environmental + SO, removal efficiencies of over 80% were achieved with sorbent injection in the furnace at various calcium-to-sulfur (Ca/S) molar ratios. + SO, removal efficiencies up to 58% were achieved with sorbent injection in the combustor at a Ca/S mo- lar ratio of 2.0. + A maximum of one-third of the coal’s sulfur was re- tained in the dry ash removed from the combustor (as slag) and furnace hearth. + At most, 11% of the coal’s sulfur was retained in the slag rejected through the combustor’s slag tap. + NO, emissions were reduced to 184 ppm by the com- bustor and furnace, and to 160 ppm with the addition of a wet particulate scrubber. + Combustor slag was essentially inert. Industrial Applications aged 72% and ranged from 55-90%. Under more fuel- lean conditions, retention averaged 80%. Meeting local particulate emissions standards required the addition of a wet venturi scrubber. Operational Combustion efficiencies of over 99% were achieved. A 3-to-1 combustor turndown capability was demon- strated. Protection of combustor refractory with slag was shown to be possible. A computer-controlled system for automatic combustor operation was developed and demonstrated. Because the technology failed to meet commercializa- tion criteria, economics were not developed during the demonstration. However, subsequent efforts indicate that incremental capital costs for installing the coal combustor in lieu of oil or gas systems are $100-200/kW. Program Update 1999 5-157 Project Summary The novel features of Coal Tech’s patented ceramic-lined, slagging cyclone combustor included its air-cooled walls and environmen- tal control of NO,, SO,, and solid waste emis- sions. Air cooling took place in a very com- pact combustor, which could be retrofitted to a wide range of industrial and utility boiler designs without disturbing the boiler’s water- steam circuit. In this technology, NO, reduc- tion was achieved by staged combustion, and SO, was captured by injection of limestone into the combustor and/or boiler. Critical to combustor performance was removal of ash as slag, which would otherwise erode boiler tubes. This was particularly important in oil furnace retrofits where tube spacing is tight (made possible by the low-ash content of oil- based fuels). The test effort consisted of 800 hours of operation, including five individual tests, each of four days, duration. An additional 100 hours of testing was performed as part of a separate ash vitrification test. Test results obtained during operation of the combustor indicated that Coal Tech attained most of the objectives contained in the cooperative agreement. About eight different Pennsylva- nia bituminous coals with sulfur contents ranging from 1.0-3.3% and volatile matter contents ranging from 19-37% were tested. Environmental Performance A maximum of over 80% SO, reduction measured at the boiler outlet stack was achieved using sorbent injection in the furnace at various Ca/S molar ratios. A maximum SO, reduction of 58% was measured at the stack with limestone injection into the combustor at a Ca/S molar ratio of 2. A maximum of one-third of the coal’s sulfur was retained in the dry ash removed from the combustor and furnace hearths, and as much as 11% of the coal’s sulfur was retained in the slag rejected through the slag 5-158 Program Update 1999 A The slagging combustor, associated piping, and control panel for Coal Tech’s advanced ceramic-lined slagging combustor are shown. tap. Additional sulfur retention in the slag is possible by increasing the slag flow rate and further improving fuel- rich combustion and sorbent-gas mixing. With fuel-rich operation of the combustor, a three- fourths reduction in measured boiler outlet stack NO, was obtained, corresponding to 184 ppm. An additional 5S— 10% reduction was obtained by the action of the wet particulate scrubber, resulting in atmospheric NO, emis- sions as low as 160 ppm. All the slag removed from the combustor produced trace metal leachates well below EPA’s Drinking Water Standard. Total ash/sorbent retention as slag in the combustor, under efficient combustion operating conditions, averaged 72% and ranged from 55-90%. Under more fuel-lean conditions, the slag retention averaged 80%. In post-CCT project, tests on flyash vitrification in the combustor, modifications to the solids injection system, and increases in the slag flow rate produced substantial increases in the slag retention rate. To meet local stack particulate emis- sion standards, a wet venturi particulate scrubber was installed at the boiler outlet. Operational Performance Combustion efficiencies exceeded 99% after proper oper- ating procedures were achieved. Combustor turndown to 6 x 10° Btu/hr from a peak of 19 x 10° Btu/hr (or a 3-to-1 turndown) was achieved. The maximum heat input dur- ing the tests was around 20 x 10° Btu/hr, even though the combustor was designed for 30 x 10° Btu/hr and the boiler was thermally rated at around 25 x 10° Btu/hr. This situa- tion resulted from facility limits on water availability for the boiler. In fact, due to the lack of sufficient water cooling, even 20 x 10° Btu/hr was borderline, so that most of the testing was conducted at lower rates. Different sections of the combustor had different materials requirements. Suitable materials for each sec- tion were identified. Also, the test effort showed that operational procedures were closely coupled with materi- als durability. As an example, by implementing certain procedures, such as changing the combustor wall tem- perature, it was possible to replenish the combustor re- fractory wall thickness with slag produced during com- bustion rather than by adding ceramic to the combustor walls. The combustor’s total operating time during the life of the CCT project was about 900 hours. This included approximately 100 hours of operation in two other flyash vitrification tests projects. Of the total time, about one-third was with coal; about 125 tons of coal were consumed. Developing proper combustor operating procedures was also a project objective. Not only were procedures for properly operating an air-cooled combustor developed, but the entire operating database was incorporated into a computer-controlled system for automatic combustor operation. Commercial Applications In conclusion, the goal of this project was to validate the performance of the air-cooled combustor at a commercial scale. While the combustor was not yet fully ready for Industrial Applications sale with commercial guarantees, it was believed to have commercial potential. Subsequent work was undertaken, which has brought the technology close to commercial introduction. Contacts Bert Zauderer, President, (610) 667-0442 Coal Tech Corporation P.O. Box 154 Merion Station, PA 19066 coaltechbz@compuserve.com William E. Fernald, DOE/HQ, (301) 903-9448 James U. Watts, NETL, (412) 386-5991 References * The Coal Tech Advanced Cyclone Combustor Demon- stration Project—A DOE Assessment. Report No. DOE/PC/79799-T 1. U.S. Department of Energy. May 1993. (Available from NTIS as DE93017043.) * The Demonstration of an Advanced Cyclone Coal Combustor, with Internal Sulfur, Nitrogen, and Ash Control for the Conversion of a 23-MMBtu/Hour Oil ized Coal; Vol. 1: Final Techni- cal Report; Vol. 2: Appendixes I-V; Vol. 3: Appendix VI. Coal Tech Corporation. August 1991. (Avail- able from NTIS as DE92002587 and DE92002588.) Fired Boiler to Pulveri * Comprehensive Report to Congress on the Clean Coal Technology Program: Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control. Coal Tech Corporation. Report No. DOE/ FE-0077. U.S. Department of Energy. February 1987. (Available from NTIS as DE87005804.) Industrial Applications A Coal Tech’s slagging combustor demonstrated the capability to retain, as slag, a high percentage of the non-fuel components injected into the combustor. The slag, shown on the conveyor, is essentially an inert, glassy by-product with value in the construction industry as an aggregate or in the manufacture of abrasives. Program Update 1999 5-159 Industrial Applications Cement Kiln Flue Gas Recovery Scrubber Project completed. Participant Passamaquoddy Tribe Additional Team Members Dragon Products Company—project manager and host HPD, Incorporated—designer and fabricator of tanks and heat exchanger Cianbro Corporation—constructor Location Thomaston, Knox County, ME (Dragon Products Company’s coal-fired cement kiln) Technology Passamaquoddy Technology Recovery Scrubber™ Plant Capacity/Production 1,450 tons/day of cement; 250,000 scfm of kiln gas; and up to 274 tons/day of coal Coal Pennsylvania bituminous, 2.5-3.0% sulfur Project Funding Total project cost $17,800,000 100% DOE 5,982,592 34 Participant 11,817,408 66 Project Objective To retrofit and demonstrate a full-scale industrial scrubber and waste recovery system for a coal-burning wet process cement kiln using waste dust as the reagent to accomplish 90-95% SO, reduction using high-sulfur eastern coals; and to produce a commercial by-product, potassium-based fertilizer by-products. Passamaquoddy Technology Recovery Scrubber is a trademark of the Passamaquoddy Tribe 5-160 Program Update 1999 4 | CEMENT. KILN (= DUST SCRUBBED EXHAUST REACTION TANK = —>—} DILUTION - TANK t | STACK KILN EXHAUST [—> J HEAT EXCHANGER RAW KILN FEED DISTILLED WATER Technology/Project Description The Passamaquoddy Technology Recovery Scrubber™ uses cement kiln dust (CKD), an alkaline-rich (potas- sium) waste, to react with the acidic flue gas. This CKD, representing about 10% of the cement feedstock otherwise lost as waste, is formed into a water-based slurry and mixed with the flue gas as the slurry passes over a perfo- rated tray that enables the flue gas to percolate through the slurry. The SO, in the flue gas reacts with the potassium to form potassium sulfate, which stays in solution and remains in the liquid as the slurry undergoes separation into liquid and solid fractions. The solid fraction, in thick- ened slurry form and freed of the potassium and other alkali constituents, is returned to the kiln as feedstock (it is the alkali content that makes the CKD unusable as feedstock). No dewatering is necessary for the wet process used at the Dragon Products Plant. The liquid fraction is passed to a crystallizer that uses waste heat in the flue gas to evaporate the water and recover dissolved alkali metal salts. A recuperator lowers the incoming flue gas tem- perature to prevent slurry evaporation, enables the use of low-cost fiberglass construction material, and provides much of the process water through condensation of ex- haust gas moisture. The Passamaquoddy Technology Recovery Scrub- ber™ was constructed at the Dragon Products Company’s cement plant in Thomaston, Maine, a plant that can pro- cess approximately 450,000 tons/yr of cement. The pro- cess was developed by the Passamaquoddy Indian Tribe while it was seeking ways to solve landfill problems, which resulted from the need to dispose of CKD from the cement-making process. Industrial Applications Calendar Year 1988 1989 3 441 2 3 4/1 2 3 4/1 2 3 1 2 3 4/1 2 3 4/1 2 3 4441 1995 2 3 4/1 2 3 4)/1 2 3 4) 1 2 1998 12/89 8/91 Design and Construction 9/88 Preaward Operation initiated 8/91 Construction completed 5/91 Preoperational tests initiated 5/91 esign completed 4/90 Operation Operation completed 9/93 Project completed/final report issued 2/94 DOE selected Environmental monitoring plan project completed 3/26/90 (CCT-Il) NEPA process completed (EA) 2/16/90 9/28/88 Cooperative agreement awarded 12/20/89 Construction started 6/89 Results Summary Environmental The SO, removal efficiency averaged 94.6% during the last several months of operation and 89.2% for the entire operating period. The NO, removal efficiency averaged nearly 25% during the last several months of operation and 18.8% for the entire operating period. All of the 250 ton/day CKD waste produced by the plant was renovated and reused as feedstock, which resulted in reducing the raw feedstock requirement by 10% and eliminating solid waste disposal costs. Particulate emission rates of 0.005—0.007 gr/scf, about one-tenth that allowed for cement kilns, were achieved with dust loadings of approximately 0.04 gr/scf. Pilot testing conducted at U.S. Environmental Protec- tion Agency laboratories under Passamaquoddy Tech- nology, L.P. sponsorship showed 98% HCI removal. Industrial Applications On three different runs, VOC (as represented by alpha- pinene) removal efficiencies of 72.3, 83.1, and 74.5% were achieved. A reduction of approximately 2% in CO, emissions was realized through recycling of the CKD. Operational During the last operating interval, April to September 1993, recovery scrubber availability (discounting host site downtime) steadily increased from 65% in April 1993 to 99.5% in July 1993. Ec onomic Capital costs are approximately $10,090,000 (1990$) for a recovery scrubber to control emissions from a 450,000-ton/yr wet process plant, with a simple pay- back estimated in 3.1 years. Operating and maintenance costs, estimated at $500,000/yr, plus capital and interest costs, are gener- ally offset by avoided costs associated with fuel, feed- stock, and waste disposal and with revenues from the sale of fertilizer. Program Update 1999 5-161 Project Summary The Passamaquoddy Technology Recovery Scrubber™ is a unique process that achieves efficient acid gas and particulate control through effective contact between flue gas and a potassium-rich slurry composed of waste kiln dust. Flue gas passes through the slurry as it moves over a special sieve tray. This results in high SO, and particu- late capture, some NO, reduction, and sufficient uptake of the potassium (an unwanted constituent in cement) to allow the slurry to be recycled as feedstock. Waste ce- ment kiln dust, exhaust gases (including waste heat), and wastewater are the only inputs to the process. Renovated cement kiln dust, potassium-based fertilizer, scrubbed exhaust gas, and distilled water are the only proven out- puts. There is no waste. The scrubber was evaluated over three basic operat- ing intervals dictated by winter shutdowns for mainte- nance and inventory and 14 separate operating periods (within these basic intervals) largely determined by un- foreseen host-plant maintenance and repairs and a de- pressed cement market. Over the period August 1991 to September 1993, more than 5,300 hours was logged, 1,400 hours in the first operating interval, 1,300 hours in the second interval, and 2,600 hours in the third interval. Sulfur loadings varied significantly over the operating periods due to variations in feedstock and operating conditions. Operational Performance Several design problems were discovered and corrected during startup. No further problems were experienced in these areas during actual operation. Two problems persisted into the demonstration pe- riod. The mesh-type mist eliminator, which was installed to prevent slurry entrainment in the flue gas, experienced plugging. Attempts to design a more efficient water spray for cleaning failed. However, replacement with a chev- ron-type mist eliminator prior to the third operating inter- val was effective. Potassium sulfate pelletization proved 5-162 Program Update 1999 to be a more difficult problem. The cause was eventually isolated and found to be excessive water entrainment due to carry-over of gypsum and syngenite. Hydroclones were installed in the crystallizer circuit to separate the very fine gypsum and syngenite crystals from the much coarser potassium sulfate crystals. Although the correction was made, it was not completed in time to realize pellet pro- duction during the demonstration period. After all modi- fications were completed, the recovery scrubber entered into the third and final operating interval—April to Sep- tember 1993. During this interval, recovery scrubber availability (discounting host site downtime) steadily increased from 65% in April to 99.5% in July. Environmental Performance An average 250 tons/day of CKD waste generated by the Dragon Products plant was used as the sole reagent in the recovery scrubber to treat approximately 250,000 scfm of flue gas. All the CKD, or approximately 10 tons/hr, were renovated and returned to the plant as feedstock and mixed with about 90 tons/hr of fresh feed to make up the required 100 tons/hr. The alkali in the CKD was con- verted to potassium-based fertilizer, eliminating all solid waste. Exhibit 5-44 lists the number of hours per operat- ing period, SO, and NO, inlet and outlet readings in pounds per hour, and removal efficiency as a percentage for each operating period. Exhibit 5-44 Summary of Emissions and Removal Efficiencies Operating Operating Inlet (lb/hr) Outlet (Ib/hr) Removal Efficiency (%) Period Time (hr) so, NO, so, NO, so, NO, l 211 73 320 10 279 87.0 12.8 2 476 71 284 11 260 84.6 08.6 3 464 87 292 13 251 85.4 14.0 4 259 131 252 16 165 87.6 34.5 5 304 245 293 28 243 88.7 17.1 6 379 222 265 28 208 87.4 21.3 7 328 281 345 28 244 90.1 29.3 8 301 124 278 10 188 91.8 32.4 9 314 47 240 7 194 85.7 19.0 10 402 41 244 6 218 86.1 10.5 ll 460 36 315 6 267 83.4 15.0 12 549 57 333 2 291 95.9 12.4 13 464 86 288 4 223 95.0 22.6 14 405 124 274 9 199 92.4 27.4 Total operating time 5,316 Weighted Average 109 289 12 234 89.2 18.8 Industrial Applications A The Passamaquoddy Technology Recovery Scrubber™ was successfully demonstrated at Dragon Products Company’s cement plant in Thomaston, Maine. Average removal efficiencies during the demonstra- tion period were 89.2% for SO, and 18.8% for NO, emis- sions. No definitive explanation for the NO, control me- chanics was available at the conclusion of the demonstration. Aside from the operating period emissions data, an assessment was made of inlet SO, load impact on removal efficiency. For SO, inlet loads in the range of 100 Ib/hr or less, recovery scrubber removal efficiency averaged 82.0%. For SO, inlet loads in the range of 100-200 Ib/hr, removal efficiency increased to 94.1% and up to 98.5% for loads greater than 200 Ib/hr. In compliance testing for Maine’s Department of Environmental Quality, the recovery scrubber was sub- jected to dust loadings of approximately 0.04 gr/scf and demonstrated particulate emission rates of 0.005—0.007 gt/scf—less than one-tenth the current allowable limit. Industrial Applications Economic Performance The estimated “as-built” capital cost to reconstruct the Dragon Products prototype, absent the modifications, is $10,090,000 in 1990 dollars. Annual operating and maintenance costs are esti- mated at $500,000. Long-term annual maintenance costs are estimated at $150,000. Power costs, estimated at $350,000/yr, are the only significant operating costs. There are no costs for reagents or disposal, and no dedi- cated staffing or maintenance equipment are required. Considering various revenues and avoided costs that may be realized by installing a recovery scrubber similar in size to the one used at Dragon Products, simple pay- back on the investment is projected in as little as 3.1 years. In making this projection, $6,000,000 was added to the “as-built” capital costs to allow for contin- gency, design/permitting, construction interest, and licensing fees. Commercial Applications Of the approximately 2,000 Portland cement kilns in the world, about 250 are in the United States and Canada. These 250 kilns emit an estimated 230,000 tons/yr of SO, (only three plants have SO, controls, one of which is the Passamaquoddy Technology Recovery Scrubber™). The applicable market for SO, control is estimated at 75% of the 250 installations. If full penetration of this estimated market were realized, approximately 150,000 tons/yr of SO, reduction could be achieved. The scrubber became a permanent part of the cement plant at the end of the demonstration. A feasibility study has been completed for a Taiwanese cement plant. Contacts Thomas N. Tureen, Project Manager, (207) 773-7166 Passamaquoddy Technology, L.P. 1 Monument Way Portland, ME 04101 (207) 773-7166 (207) 773-8832 (fax) William E. Fernald, DOE/HQ, (301) 903-9448 John C. McDowell, NETL, (412) 386-6175 References * Passamaquoddy Technology Recovery Scrubber™: Volumes | and 2 (Appendices A—M. Passamaquoddy Tribe. February 1994. (Vol. 1 avail- able from NTIS as DE94011175, Vol. 2 as DE94011176.) Final Report. * Passamaquoddy Technology Recovery Scrubber™: Public Design Report. Report No. DOE/PC/89657- T2. Passamaquoddy Tribe. October 1993. (Avail- able from NTIS as DE940083 16.) * Passamaquoddy Technology Recovery Scrubber™: Topical Report. Report No. DOE/PC/89657-T1. Passamaquoddy Tribe. March 1992. (Available from NTIS as DE92019868.) * Comprehensive Report to Congress on the Clean Coal Technology Program: Cement Kiln Flue Gas Recovery Scrubber. Passamaquoddy Tribe. Report No. DOE/FE-0152. U.S. Department of Energy. No- vember 1989. (Available from NTIS as DE90004462.) Program Update 1999 5-163 Appendix A: Historical Perspective and Legislative History Historical Perspective There were a number of key events that prompt- ed creation of the CCT Program and impacted its focus over the course of the five solicitations. The roots of the CCT Program can be traced to the acid rain debates of the early 1980s, culminating in U.S. and Canadian envoys recommending a five year, $5 billion U.S. effort to curb precursors to acid rain formation—SO, and NO,. This recommendation was adopted and became a presidential initiative in March 1987. As a part of the response to the recommenda- tions of the Special Envoys on Acid Rain in April 1987, the President directed the Secretary of Energy to establish a panel to advise the President on innova- tive clean coal technology activities. This panel was the Innovative Control Technology Advisory Panel. As a part of the panel’s activities, the state and federal incentive subcommittee prepared a report, Report to the Secretary of Energy Concerning Com- mercialization Incentives, that addressed actions that states could take to provide incentives for demon- strating and deploying clean coal technologies. The panel determined that demonstration and deployment should be managed through both state and federal initiatives. In the same time frame, the Vice President’s Task Force on Regulatory Relief (later referred to as the Presidential Task Force on Regulatory Relief) was established. Among other things, the task force was asked to examine incentives and disincentives to the commercial realization of new clean coal technol- ogies. The task force also examined cost-effective emissions reduction measures that might be inhibited by various federal, state, and local regulations. The task force recommended that preference be given to projects located in states that offer certain regulatory incentives to encourage such technologies. This recommendation was accepted and became part of the project selection considerations beginning with CCT-IL. Initial CCT Program emphasis was on control- ling SO, and NO, emissions from existing coal-based power generators. Approaches demonstrated through the program were coal processing to produce clean fuels, combustion modification to control emissions, postcombustion cleanup of flue gas, and repowering with advanced power generation systems. These early efforts (projects resulting from the first three solicitations) produced a suite of cost-effective com- pliance options available today to address acid rain concerns. As the CCT Program evolved, work began on drafting what was to become the Clean Air Act Amendments of 1990. Through a dialog with EPA and Congress, the program was able to remain responsive to shifts in environmental emphasis. Also, projects in place enabled CAAA architects to have access to real-time data on emission control capabilities while structuring proposed acid rain regulations under Title IV of the CAAA. Aside from acid rain, there was an emerging issue in the area of hazardous air pollutants (HAPs), also referred to as air toxics. Title III of the CAAA listed 189 airborne compounds subject to control, including trace ele- ments and volatile and semi-volatile compounds. To assess the impacts on coal-based power generation, CCT Program projects were leveraged to obtain data through an integrated effort among DOE, EPA, EPRI, and the Utility Air Regulatory Group. Through this effort, concerns about HAPs relative to coal-based power generation have been significantly mitigated, enabling focus on but a few flue gas constituents. Also, because NO, is a precursor to ozone formation, the presence of NO, in ozone nonattainment areas, even at low levels, became an issue. This precipitated action in the CCT Program to include technologies capable of deep NO, reduc- tion in the portfolio of technologies sought. In the course of the last two solicitations of the CCT Program, a number of energy and environmen- tal considerations combined to change the emphasis toward seeking high-efficiency, very-low-emission power generation technology. Energy demand Program Update 1999 A-1 projections in the United States showed the need for continued reliance on coal-based power generation, with significant growth required into the 21st centu- ry. The CAAA, however, capped SO, emissions at year 2000 levels, and NO, continued to receive increased attention relative to ozone nonattainment. Furthermore, particulate emissions were coming under increased scrutiny because of correlations with lung disorders and the tendency for toxic compounds to adhere to particulate matter. Added to these concerns was the growing concern over global warm- ing, and more specifically, the CO, produced from burning fossil fuels. Coal became a primary target because of the high carbon-to-hydrogen ratio relative to natural gas, resulting in somewhat higher CO, emissions per unit of energy produced. However, coal is the fuel of choice (if not necessity) for many developing countries where projected growth in electric power generation is the greatest. The path chosen to respond to these considerations was to pursue advanced power generation systems that could provide major enhancements in efficiency and con- trol SO,, NO,, and particulates without introducing external parasitic control devices. (Increased effi- ciency translates to less coal consumption per unit of energy produced.) As a result, a number of advanced power generation projects were undertaken, repre- senting pioneer efforts recognized throughout the world. Legislative History The legislation authorizing the CCT Program is found in Public Law 98-473, Joint Resolution Mak- ing Continuing Appropriations for Fiscal Year 1985 A-2 Program Update 1999 and for Other Purposes. Title I set aside $750 mil- lion of the congressionally rescinded $5.375 billion of the Synthetic Fuels Corporation into a special U.S. Treasury account entitled the “Clean Coal Technolo- gy Reserve.” This account was dedicated to “con- ducting cost-shared clean coal technology projects for the construction and operation of facilities to demon- strate the feasibility of future commercial applica- tions of such technology.” Title III of this act direct- ed the Secretary of Energy to solicit statements of interest in and proposals for clean coal projects. In keeping with this mandate, DOE issued a program announcement, which resulted in the receipt of 176 proposals representing both domestic and interna- tional projects with a total estimated cost in excess of $8 billion. After this significant initial expression of inter- est in clean coal demonstration projects, Public Law 99-190, enacted December 1985, appropriated $400 million to conduct cost-shared demonstration projects. Of the total appropriated funds, approxi- mately $387 million was made available for cost- shared projects to be selected through a competitive solicitation, or Program Opportunity Notice (PON), referred to as CCT-I. (The remaining funds were required for program direction and the legislatively mandated Small Business Innovation Research Program [SBIR] and Small Business Technology Transfer Program [STTR].) In a manner similar to the initiation of CCT-I, Congress again directed DOE to solicit information from the private sector in the Department of the Interior and Related Agencies Appropriations Act for FY 1987 (Public Law 99-591, enacted October 30, 1986). The information received was to be used to establish the level of potential industrial interest in another solicitation, this time involving clean coal technologies capable of retrofitting, repowering, or modernizing existing facilities. Projects were to be cost-shared, with industry sharing at least 50 percent of the cost. As a result of the solicitation, a total of 39 expressions of interest were received by DOE in January 1987. On March 18, 1987, the President announced the endorsement of the recommendations of the Special Envoys on Acid Rain, including a $2.5 billion gov- ernment share of funding for industry/government demonstrations of innovative control technology over a five year period. The Secretary of Energy stated that the department would ask Congress for an additional $350 million in FY 1988 and an ad- vanced appropriation of $500 million in FY 1989. Additional appropriations of $500 million would be requested in fiscal years 1990, 1991, and 1992. This request was made by the President on April 4, 1987. Public Law 100-202, enacted December 22, 1987, as amended by Public Law 100-446, appropri- ated a total of $575 million to conduct CCT-II. About $536 million was for projects, with the re- mainder for program direction and the SBIR and STTR Programs. The Department of the Interior and Related Agencies Appropriations Act for FY 1989 (Public Law 100-446, enacted September 27, 1988) provided $575 million for necessary expenses associated with clean coal technology demonstrations in the CCT-III solicitation. Of the total funding, about $546 million was made available for cost-sharing projects, with the remainder for program direction and the SBIR and STTR Programs. The act continued the requirement that proposals must demonstrate technologies capable of retrofitting or repowering existing facilities. The statute also authorized the use of Tennessee Valley Authority power program funds as a source of non- federal cost-sharing, except if provided by annual appropriations acts. In addition, funds borrowed by Rural Electrification Administration )now Rural Utilities Service) electric cooperatives from the Federal Financing Bank became eligible as cost- sharing in the CCT-III solicitation, except if provided by annual appropriations. In the Department of the Interior and Related Agencies Appropriations Act of 1990 (Public Law 101-121, enacted October 23, 1989), Congress provided $600 million for the CCT-IV solicitation. CCT-IV, according to the act, “shall demonstrate technologies capable of replacing, retrofitting, or repowering existing facilities and shall be subject to all provisos contained under this head in Public Laws 99-190, 100-202 and 100-446 as amended by this Act.” About $563 million was made available for federal cofunding of projects selected in CCT-IV, with the remainder for program direction and the SBIR and STTR Programs. In Public Law 101-121, enacted October 23, 1989, Congress also provided $600 million for the CCT-V solicitation. CCT-V, according to the act, “shall be subject to all provisos contained under this head in Public Laws 99-190, 100-202 and 100-446 as amended by this Act.” Approximately $568 million was made available for federal cofunding of projects to be selected in this solicitation, with the remainder again for program direction and the SBIR and STTR Programs. Subsequent acts (Public Laws 101-164, 101-302, 101-512, and 102-154) modified the schedule for issuing CCT-IV and/or CCT-V PONs and selecting projects. In Public Law 101-512, Congress directed DOE to issue the PON for CCT-IV not later than February 1, 1991, with selections to be made within 8 months. In Public Law 102-154, Congress directed DOE to issue CCT-V PON not later than July 6, 1992, with selections to be made within 10 months. This later act also directed that CCT-V proposals should advance significantly the efficiency and environmental performance of coal-using technolo- gies and be applicable to either new or existing facilities. Public Laws 101-164, 101-302, 101-512, 103- 138, and 103-332 adjusted the rate at which funds were to be made available to the program. CCT Program funds have been further adjusted through sequestering requirements of the Gramm- Rudman-Hollings Deficit Reduction Act as well as rescissions. Sequestering reduced CCT Program appropriations as follows: + $2.4 million was sequestered from the $400 million appropriated by Public Law 99-190. + $2,600 was sequestered from the $575 million appropriated by Public Law 100-202, as amended by Public Law 100-446. * $2,028 was sequestered from the $575 million appropriated by Public Law 100-446, as amended by Public Law 101-164. + $455 was sequestered from the $1.2 billion appropriated by Public Law 101-121, as amended by Public Laws 101-512, 102-154, 102-381, 103-138, 103-332, 104-6, 104-208, and 105-18. Rescissions have reduced CCT Program appro- priations as follows: * $200 million was rescinded by Public Law 104-6. + $123 million was rescinded by Public Law 104-208. + $17 million was rescinded by Public Law 105-18. + $101 million was rescinded by Public Law 105-83. + $38,000 was rescinded by Public Law 106- 113 (general reduction). In 1998, $40 million of the CCT program funds were deferred by Public Law 105-277. Funds will be restored over a three year period beginning October 1, 1999. Again in 1999, Congress deferred program funds. In Public Law 106-113, Congress deferred $156,000,000 until October 1, 2000. Exhibit A-1 lists all the key legislation relating to the CCT Program and provides a summary of provisions relating to program funding as well as program implementation. Following this exhibit are funding provisions excerpted from appropriations and other relevant funding-related acts. Program Update 1999 A-3 Exhibit A-1 CCT Program Legislative History Public Date Law Enacted CCT Round Program Funding Implementation Provisions 98-473 10/12/84 99-88 8/15/85 99-190 12/19/85 99-591 10/30/86 100-202 12/22/87 Initiation of CCT Program; informational solicitation CCT-I Second informational solicitation CCT-II Rescinded $750 million of $5.375 billion from the Energy Security Reserve (Synthetic Fuels Corporation) to be deposited in a U.S. Treasury Department account entitled “Clean Coal Technology Reserve” for conducting cost- shared CCT projects for the construction and operation of facilities to demonstrate the feasibility for future commer- cial application of such technology, without fiscal year limitation, subject to subsequent annual appropriation. Deferred $1.6 million for obligation until 10/1/85. Conference Report (H. Rep. 99-450) agreed to a $400-million CCT Program as described under the U.S. Treasury Department Energy Security Reserve, with the request for proposals to be for the full $400 million. (Contained no funding provisions for CCT Program) Appropriated $50 million for FY beginning 10/1/87 until expended and $525 million for FY beginning 10/1/88 until expended. Title III required publication of a notice soliciting statements of interest in and proposals for projects employing emerging CCTs. A report to Congress was required no later than 4/15/85. Conference Report (H. Rep. 99-236) concurred with CCT project guidelines contained in Senate Report 99-82, with certain modifications. Required a PON (CCT-I) to be issued and projects to be selected no later than 8/1/86. Project cost-sharing provisions were detailed. Title II required publication of a notice soliciting statements of interest in, and informational proposals for projects employing emerging CCTs capable of retrofitting, repowering, or modernizing existing facilities. A report to Congress was required no later than 3/6/87. Required a request for proposals (CCT-II) to be issued no later than 60 days following enactment, for emerg- ing CCTs capable of retrofitting or repowering existing facilities. Extended project selection from 120 days to 160 days after receipt of proposals. Provided for cost- sharing of pre-award costs for preparation and submis- sion of environmental data upon signing of the cooperative agreement. Conference Report (H. Rep. 100-498) provided that project cost-sharing funds be made available to nonutility as well as utility applica- tions. No funds were made available for new, stand- alone applications. H. Rep. Report 100-171 and Senate Report 100-165 outlined provisions for participant to repay government contributions. A-4 — Program Update 1999 Exhibit A-1 (continued) CCT Program Legislative History Public Enacted CCT Round Program Funding Implementation Provisions 100-446 9/27/88 CCT-II 101-45 6/30/89 CCT-III 101-121 10/23/89 CCT-IV and CCT-V 101-164 11/21/89 CCT-IV and CCT-V 101-302 5/25/90 CCT-IV and CCT-V Wu Made available $575 million on 10/1/89 until expended. Pub. L. 100-202 was amended by striking $525 million and inserting $190 million for FY beginning 10/1/88 until expended, $135 million for fiscal year beginning 10/1/89 until expended, and $200 million for FY beginning 10/1/90 until expended, provided that outlays for FY89 resulting from use of funds appropriated under Pub. L. 100-202, as amended, did not exceed $15.5 million. Funds appropriated for FY 1989 were made available for a third solicitation. Made available $600 million on 10/1/90 until expended and $600 million on 10/1/91 until expended. Pub. L. 100- 446 was amended by striking $575 million and inserting $450 million to be made available on 10/1/89 until expended and $125 million to be made available on 10/1/90, Unobligated balances excess to the needs of the procurement for which they originally were made available may be applied to other procurements for which requests for proposals had not yet been issued, except that no supplemental, backup, or contingent selection of projects could be made over and above the projects originally selected. Appropriation for FY1990 was amended by striking $450 million and inserting $419 million and by striking $125 million and inserting $156 million. Obligation of funds previously appropriated for CCT-IV and CCT-V was deferred until 9/1/91. Request for proposals (CCT-III) to be issued by 5/1/89 for emerging CCTs capable of retrofitting or repowering existing facilities. Proposals were to be due 120 days after issuance of the PON; projects were to be selected no later than 120 days after receipt of proposals. Funds borrowed by REA electric cooperatives from the Federal Financing Bank were made eligible as cost- sharing. Funds derived by the Tennessee Valley Authority from its power program were deemed allowable as cost-sharing except if provided by annual appropriations acts. Project selections for the third solicitation were to be made not later than 1/1/90. Two solicitations (CCT-IV and CCT-V) to be issued, one for each appropriation, to demonstrate technologies capable of replacing, retrofitting, or repowering existing facilities, subject to all provisos contained in Pub. L. 99-190, 100-202, and 100-446 as amended. The PON (CCT-IV) using funds becoming available on 10/1/90 was to be issued by 6/1/90, with selections made by 2/1/91. The PON (CCT-V) using funds becoming available on 10/1/91 was to be issued no later than 9/1/91, with selections made by 5/1/92. Solicitations could not be conducted prior to ability to obligate funds. Repayment provisions for CCT-IV and CCT-V were to be the same as for CCT-III. Program Update 1999 A-5 Exhibit A-1 (continued) CCT Program Legislative History Public Date Law Enacted CCT Round Program Funding Implementation Provisions 101-512 11/5/90 CCT-IV and CCT-V Pub. L. 101-121 was amended by striking $600 million The CCT-IV solicitation was to be issued not later than made available on 10/1/90 until expended and $600 2/1/91. The CCT-V PON was to be issued not later million made available on 10/1/91 until expended and than 3/1/92. Project selections were to be made within inserting $600 million made available as follows: $35 eight months of PON’s issuance. Repayment provisions million on 9/1/91, $315 million on 10/1/91, and $250 were to be the same as for CCT-III. Provisions were million on 10/1/92, all sums remaining until expended, for included to provide protections for trade secrets and use in conjunction with a separate general request for proprietary information. Conference Report (H. Rep. proposals, and $600 million made available as follows: 101-971) recommends changes to program policy $150 million on 10/1/91, $225 million on 10/1/92, and factors. $225 million on 10/1/93, all sums remaining until expended, for use with a separate general request for proposals. 102-154 11/13/91 CCT-V Pub. L. 102-512 was amended by striking $150 million on The CCT-V PON was delayed to not later than 10/1/91 and $225 million on 10/1/92 and inserting 7/6/92, with selection to be made within 10 months $100 million on 10/1/91 and $275 million on 10/1/92. (extended by two months). The PON was to be for projects that advance significantly the efficiency and environmental performance of coal-using technologies and be applicable to either new or existing facilities. Conference Report (H. Rep. 102-256) stated expecta- tions that the CCT-V solicitation would be conducted under the same general types of criteria as CCT-IV, principally modified only to (1) include the wider range of eligible technologies or applications; (2) adjust technical criteria to consider allowable development activities, strengthen criteria for nonutility demonstra- tions, and adjust commercial performance criteria for additional facilities and technologies with regard to aspects of general energy efficiency and environmental performance; and (3) clarify and strengthen cost and finance criteria, particularly with regard to development activities. Funding was allowed for project-specific development activities for process performance definition, component design verification, materials selection, and evaluation of alternative designs on a cost-shared basis up to a limit of 10 percent of the government share of project cost. == A-6 Program Update 1999 Exhibit A-1 (continued) CCT Program Legislative History Public Date Law Enacted CCT Round Program Funding Implementation Provisions 102-154 Development activities eligible for cost-sharing (continued) 102-381 10/5/92 102-486 10/24/92 103-138 11/11/93 103-332 9/30/94 Pub. L. 101-512 was amended by striking $250 million on 10/1/92 and inserting $150 million on 10/1/93 and $100 million on 10/1/94; and by striking $275 million on 10/1/92 and $225 million on 10/1/93 and inserting $250 million on 10/1/93 and $250 million on 10/1/94. (Contained no funding provisions for CCT Program) Pub. L. 101-512 was amended by striking $150 million on 10/1/93 and $100 million on 10/1/94 and inserting $100 million on 10/1/93, $100 million on 10/1/94, and $50 million on 10/1/95; and by striking $250 million on 10/1/93 and $250 million on 10/1/94 and inserting $125 million on 10/1/93, $275 million on 10/1/94, and $100 million on 10/1/95. Pub. L. 101-512 was amended by striking $100 million on 10/1/94 and $50 million on 10/1/95 and inserting $18 million on 10/1/94, $100 million on 10/1/95, and $32 million on 10/1/96; and by striking $275 million on 10/1/94 and $100 million on 10/1/95 and inserting $19.121 million on 10/1/94, $100 million on 10/1/95, and $255.879 million on 10/1/96. included limited modifications to existing facilities for project-related testing but not construction of new facilities. Section 1301—Coal RD&D and Commercial Applica- tions Programs (Title XIII; Subtitle A) authorized DOE to conduct programs for RD&D and commercial applications of coal-based technologies. Secretary of Energy was directed to submit to Congress (1) a report that included, among other things, recommendations regarding the manner in which the cost-sharing demonstrations conducted pursuant to the Clean Coal Program (Pub. L. 98-473) might be modified and extended in order to ensure the timely demonstration of advanced coal-based technologies and (2) periodic status reports on the development of advanced coal- based technologies and RD&D and commercial application attributes. An amount not to exceed $18 million available in FY1995 may be used for administrative oversight of the CCT Program. Program Update 1999 A-7 Exhibit A-1 (continued) CCT Program Legislative History Public Date Law Enacted CCT Round Program Funding Implementation Provisions 104-6 4/10/95 Of funds available for obligation in FY 1996, $50 million was rescinded. Of the funds to be made available for obligation in FY 1997, $150 million was rescinded. 104-134" 4/26/96 Conference Report (H. Rep. 104-402 to accompany H.R. 1977) allowed for the use of up to $18 million in CCT Program funds for program administration. 104-208" 9/30/96 Conference Report (H. Rep. 104-863 to accompany House and Senate committees did not object to use of H.R. 3610) noted rescission of $123 million for FY 1997 or up to $16 million in available funds for administration prior years. of the CCT Program in FY 1997 (H. Rep. 104-625 and Senate 104-319 to accompany H.R. 3662). 105-18 6/12/97 Of funds made available for obligation in FY1997 or prior years, $17 million was rescinded. 105-83 11/14/97 Of funds made available for obligation in FY 1997 or priors, $101 million was rescinded. 105-277 10/21/98 Of funds made available for obligation in prior years, Conference Report allowed $14.9 million in CCT $40 million was deferred. Program funds for program administration. 106-113 11/29/99 Of funds made available for obligation in prior years, $156 Conference Report did not object to the use of up to A-8 Program Update 1999 million was deferred. $38,000 was rescinded as a result of the general reduction. * H.R. 3019, which became Pub. L. 104-134, replaced H.R. 1977. 6 H.R. 3610, which became Pub. L. 104-208, replaced H.R. 3662. $14.4 million in CCT Program funds for program administration. Public Law 99-190 Public Law 99-190, 99 Stat. 1251 (1985) CLEAN CoaL TECHNOLOGY Within 60 days following enactment of this Act [Dec. 19, 1985] the Secretary of Energy shall, pursuant to the Federal Nonnuclear Energy Research and Develop- ment Act of 1974 (42 U.S.C. 5901, et seq.), issue a general request for proposals for clean coal technology projects for which the Secretary of Energy upon review may provide financial assistance awards. Proposals for clean coal technology projects under this section shall be submitted to the Department of Energy within 60 days after issuance of the general request for proposals. The Secretary of Energy shall make any project selections no later than August 1, 1986: Provided, That the Secretary may vest fee title or other property interests acquired under cost-shared clean coal technology agreements in any entity, including the United States: Provided further, That the Secretary shall not finance more than 50 per centum of the total costs of a project as estimated by the Secretary as of the date of award of financial assistance: Provided further, That cost-sharing by project sponsors is required in each of the design, construction, and operating phases proposed to be included in a project: Provided further, That financial assistance for costs in excess of those estimated as of the date of award of original financial assistance may not be provided in excess of the proportion of costs borne by the Government in the original agreement and only up to 25 per centum of the original financial assistance: Provided further, That revenues or royalties from prospective operation of projects beyond the time considered in the award of financial assistance, or proceeds from prospective sale of the assets of the project, or revenues or royalties from replication of technology in future projects or plants are not cost-sharing for the purposes of this appropriation: Provided further, That other appropriated Federal funds are not cost-sharing for the purposes of this appropriation: Provided further, That existing facilities, equipment, and supplies, or previously expended research or development funds are not cost-sharing for the purposes of this appropriation, except as amortized, depreciated, or expensed in normal business practice. Conference Report (H.R. Conf. Rep. No. 450, 99th Cong., Ist Sess. [1985]) CLEAN CoAL TECHNOLOGY The managers have agreed to a $400,000,000 Clean Coal Technology program as described under the Department of the Treasury, Energy Security Reserve. Bill language is included which provides for the selection of projects no later than August 1, 1986. Within that period, a general request for proposals must be issued within 60 days and proposals must be submitted to the Department within 60 days after issuance of the general request for proposals. Language is also included allowing the Secretary of Energy to vest title in interests acquired under agreements in any entity, including the United States, and delineating cost-sharing requirements. Funds for these activities and projects are made available to the Clean Coal Technology program in the Energy Security program. It is the intent of the managers that contributions in the form of facilities and equipment be considered only to the extent that they would be amortized, depreciated or expensed in normal business practice. Normal business practice shall be determined by the Secretary and is not necessarily the practice of any single proposer. Property which has been fully depreciated would not receive nay cost-sharing value except to the extent that it has been in continuous use by the proposer during the calendar year immediately preceding the enactment of this Act. For this property, a fair use value for the life of the project may be assigned. Property offered as a cost- share by the proposer that is currently being depreciated would be limited in its cost- share value to the depreciation claimed during the life of the demonstration project. Furthermore, in determining normal business practice, the Secretary should not accept valuation for property sold, transferred, exchanged, or otherwise manipulated to acquire a new basis for depreciation purposes or to establish a rental value in circumstances which would amount to a transaction for the mere purpose of participating in this program. The managers agree that, with respect to cost-sharing, tax implications of proposals and tax advantages available to individual proposers should not be considered in determining the percentage of Federal cost-sharing. This is consistent with current and historical practices in Department of Energy procurements. Program Update 1999 A-9 It is the intent of the managers that there be full and open competition and that the solicitation be open to all markets utilizing the entire coal resource base. However, projects should be limited to the use of United States mined coal as the feedstock and demonstration sites should be located within the United States. The managers agree that no more than $1,500,000 shall be available in FY 1986 and $2,000,000 each year thereafter for contracting, travel and ancillary costs of the program, and that manpower costs are to be funded under the fossil energy research and development program. The managers direct the Department, after projects are selected, to provide a comprehensive report to the Congress on proposals received. The managers also expect the request for proposals to be or the full $400,000,000 program, and not only for the first $100,000,000 available in fiscal year 1986. Public Law 100-202 Public Law 100-202, 101 Stat. 1329-1 (1987) CLEAN CoAL TECHNOLOGY For necessary expenses of, and associated with, Clean Coal Technology demon- strations pursuant to 42 U.S.C. 5901 et seq., $50,000,000 are appropriated for the fiscal year beginning October 1, 1987, and shall remain available until expended, and $525,000,000 are appropriated for the fiscal year beginning October 1, 1988, and shall remain available until expended. No later than sixty days following enactment of this Act, the Secretary of Energy shall, pursuant to the Federal Nonnuclear Energy Research and Development Act of 1974 (42 U.S.C. 5901 et seq.), issue a general request for proposals for emerging clean coal technologies which are capable of retrofitting or repowering existing facilities, for which the Secretary of Energy upon review may provide financial assistance awards. Proposals under this section shall be submitted to the Department of Energy no later than ninety days after issuance of the general request for proposals required herein, and the Secretary of Energy shall make any project selections no later than one hundred and sixty days after receipt of proposal: Provided, That projects A-10 Program Update 1999 selected are subject to all provisos contained under this head in Public Law 99-190: Provided further, That pre-award costs incurred by project sponsors after selection and before signing an agreement are allowable to the extent that they are related to (1) the preparation of material requested by the Department of Energy and identified as required for the negotiation; or (2) the preparation and submission of environmen- tal data requested by the Department of Energy to complete National Environmental Policy Act requirements for the projects: Provided further, That pre-award costs are to be reimbursed only upon signing of the project agreement and only in the same ratio as the cost-sharing for the total project: Provided further, That reports on projects selected by the Secretary of Energy pursuant to authority granted under the heading “Clean coal technology” in the Department of the Interior and Related Agencies Appropriations Act, 1986, as contained in Public Law 99-190, which are received by the Speaker of the House of Representatives and the President of the Senate prior to the end of the first session of the 100th Congress shall be deemed to have met the criteria in the third proviso of the fourth paragraph under the heading “Administrative provision, Department of Energy” in the Department of the Interior and Related Agencies Appropriations Act, 1986, as contained in Public Law 99-190, upon expiration of 30 calendar days from receipt of the report by the Speaker of the House of Representatives and the President of the Senate. Conference Report (H.R. Conf. Rep. No. 498, 100th Cong., Ist Sess. [1987]) CLEAN CoAL TECHNOLOGY Appropriates $575,000,000 for clean coal technology instead of $350,000,000 as proposed by the House and $850,000,000 as proposed by the Senate. The comparison by year is as follows: House Senate Conference Fiscal year: 1988 $50,000,000 $350,000,000 $50,000,000 1989 200,000,000 500,000,000 525,000,000 1990 100,000,000 TT Total 350,000,000 850,000,000 575,000,000 Bill language, proposed by the House, which would have prohibited using grants has been deleted. The managers agree that project funding is expected to be based on cooperative agreements, but that grants might be applicable to support work also funded from this account. The managers agree to deleted Senate language providing personnel floors for Clean Coal Technology. The managers further agree that the budget estimates for personnel and contract support are to be followed. The agreement included 58 new positions above current employment floors for the fossil energy organization and 30 positions within the floors. Out of clean coal technology funds, up to $3,980,000 is for fiscal year 1988 personnel-related costs and up to $16,520,000 is for all contract costs needed to make project selections and complete negotiations for both clean coal procurements. Contract costs necessary to monitor approved projects should be requested in the fiscal year 1989 budget. Increases above to those amount are subject to reprogramming procedures. No funds other than personnel related costs for the 30 positions included in the program direction are to be provided from the fossil energy research and development account. The length of time for selection of projects by the Secretary of Energy has been extended from 120 days to 160 days based on experience from the original clean coal procurement. Once projects have been selected the Secretary should establish project milestones and guidelines for project negotiations in order to expedite the negotiation process to the extent feasible. The managers agree that the funds provided are available for non-utility applications as well as for utility applications. The managers agree that no funds are provided for the demonstration of clean coal technologies which are intended solely for new, stand alone, applications. The Senate had proposed up to 25% of the funds be available for this purpose. Bill language has been included which provides that reports on projects selected in the first round of clean coal procurements that are received before the end of the first session of the 100th Congress will satisfy reporting requirements 30 calendar days after receipt by Congress. This provision applies to a maximum of two project reports. Public Law 100-446 Public Law 100-446, 102 Stat. 1774 (1988) CLEAN CoAL TECHNOLOGY For necessary expenses of, and associated with, Clean Coal Technology demon- strations pursuant to 42 U.S.C. 5901 et seq., $575,000,000 shall be made available on October 1, 1989, and shall remain available until expended: Provided, That projects selected pursuant to a general request for proposals issued pursuant to this appropriation shall demonstrate technologies capable of retrofitting or repowering existing facilities and shall be subject to all provisions contained under this head in Public Laws 99-190 and 100-202 as amended by this Act. The first paragraph under this head in Public Law 100-202 is amended by striking “and $525,000,000 are appropriated for the fiscal year beginning October 1, 1988” and inserting “$190,000,000 are appropriated for the fiscal year beginning October 1, 1988, and shall remain available until expended, $135,000,000 are appropriated for the fiscal year beginning October 1, 1989, and shall remain available until expended, and $200,000,000 are appropriated for the fiscal year beginning October 1, 1990”: Provided, That outlays in fiscal year 1989 resulting from the use of funds appropriated under this head in Public Law 100-202, as amended by this Act, may not exceed $15,500,000: Provided further, That these actions are taken pursuant to section 202(b)(1) of Public law 100-119 (2 U.S.C. 909). For the purposes of the sixth proviso under this head in Public Laws 99-190, funds derived by the Tennessee Valley Authority from its power program are hereafter not to be precluded from qualifying as all or part of any cost-sharing requirement, except to the extent that such funds are provided by annual appropri- ations Acts: Provided, That unexpended balances of funds made available in the “Energy Security Reserve” account in the Treasury for the Clean Coal Technology Program by the Department of the Interior and Related Agencies Appropriations Acts, 1986, as contained in section 101(d) of Public Law 99-190, shall be merged with this account: Provided further, That for the purposes of the sixth proviso in Public Law 99-190 under this heading, funds provided under section 306 of Public Law 93- 32 shall be considered non-Federal: Provided further, That reports on projects selected by the Secretary of Energy pursuant to authority granted under the heading Program Update 1999 A-11 “Clean coal technology” in the Department of the Interior and Related Agencies Appropriations Act, 1986, as contained in Public Law 99-190, which are received by the Speaker of the House of Representatives and the President of the Senate prior to the end of the second session of the 100th Congress shall be deemed to have met the criteria in the third proviso of the fourth paragraph under the heading “Administra- tive provisions, Department Energy” in the Department of the Interior and Related Agencies Appropriations Act, 1986, as contained in Public Law 99-190, upon expiration of 30 calendar days from receipt of the report by the Speaker of the House of Representatives and the President of the Senate. Conference Report (H.R. Conf. Rep. No. 862, 100th Cong., 2nd Sess. [1988]) CLEAN Coat TECHNOLOGY Amendment No. 131: Reported in technical disagreement. The managers on the part of the House will offer a motion to recede and concur in the amendment of the Senate with an amendment as follows: In lieu of the matter proposed by said amendment insert the following: For necessary expenses of, and associated with, Clean Coal Technology demonstrations pursuant to 42 U.S.C. 5901 et seq., $575,000,000 shall be made available on October 1, 1989, and shall remain available until expended: Provided, That projects selected pursuant to a general request for proposals issued pursuant to this appropriation shall demonstrate technologies capable of retrofitting or repowering existing facilities and shall be subject to all provisos contained under this head in Public Laws 99-190 and 100-202 as amended by this Act. The managers on the part of the Senate will move to concur in the amendment of the House to the amendment of the Senate. The amendment provides $575,000,000 in fiscal year 1990 for a third Clean Coal Technology procurement as proposed by the Senate, and clarifies that the procurement is for retrofit and repowering technologies and is subject to the cost-sharing provisions of the previous two procurements. The managers agree that a request for proposals should be issued by May 1, 1989, with proposals due no later than 120 days after issuance of the request for proposals, and that the Secretary of Energy should make project selections no later than 120 days after receipt of proposals. A-12— Program Update 1999 Amendment No, 132: Reported in technical disagreement. The managers on the part of the House will offer a motion to recede and concur in the amend- ment of the Senate with an amendment as follows: Restore the matter stricken by said amendment, amended to read as follows: The first paragraph under this head in Public Law 100-202 is amended by striking “and $525,000,000 are appropriated for the fiscal year beginning October 1, 1988” and inserting “$190,000,000 are appropriated for the fiscal year beginning October 1, 1988, and shall remain available until expended, $135,000,000 are appropriated for the fiscal year beginning October 1, 1989, and shall remain available until expended, and $200,000,000 are appropriated for the fiscal year beginning October 1, 1990”: Provided, That outlays in fiscal year 1989 resulting from the use of funds appropriated under this head in Public Law 100-202, as amended by this Act, may not exceed $15,500,000. Provided further, That these actions are taken pursuant to section 202(b)(1) of Public Law 100-119 (2 U.S.C. 909). The managers on the part of the Senate will move to concur in the amendment of the House to the amendment of the Senate. The amendment changes the availability of $525,000,000 originally made available for fiscal year 1989 in Public Law 100-202 by making $190,000,000 available in 1989, $135,000,000 available in 1990, and $200,000,000 available in 1991 and also provides an outlay ceiling in fiscal year 1989. The House had proposed $100,000,000 in fiscal year 1989, $225,000,000 in fiscal year 1990, and $200,000,000 in fiscal year 1989, $225,000,000 in fiscal year 1990, and $200,000,000 in fiscal year 1991, and the Senate struck the House language. Both of these changes are necessary because of budget allocation constraints, but neither action has an effect on the execution of the Clean Coal program, or on the Congress’ overall support for the program, as is evidenced by additional appropri- ations provided for a third procurement of technologies. The managers agree that administrative contract expenses may be incurred up to the budget level of $9,820,000, but caution that close control of such expenditures is necessary to assure that the outlay ceiling provided will be sufficient to cover project costs. Amendment No. 133: Modifies public law citation as proposed by the Senate. Amendment No. 134: Reported in technical disagreement. The managers on the part of the House will offer a motion to recede and concur in the amendment of the Senate which clarifies that funds borrowed by REA Electric Cooperatives from the Federal Financing Bank are eligible as cost-sharing in the clean coal technology program. Amendment No. 135: Reported in technical disagreement. The managers on the part of the House will offer a motion to recede and concur in the amend- ment of the Senate which specifies clean coal projects may proceed 30 calendar days after receipt by Congress of required reports, provided the reports are re- ceived prior to the end of the 100th Congress. Public Law 101-45 Public Law 101-45, 103 Stat. 97 (1989) CLEAN CoAL TECHNOLOGY Notwithstanding any other provision of law, funds originally appropriated under this head in the Department of the Interior and Related Agencies Appropri- ations Act, 1989, shall be available for a third solicitation of clean coal technolo- gy demonstration projects, which projects are to be selected by the Department not later than January 1, 1990. Public Law 101-121 Public Law 101-121, 103 Stat. 701 (1989) CLEAN Coat TECHNOLOGY For necessary expenses of, and associated with, Clean Coal Technology demonstrations pursuant to 42 U.S.C. 5901 et seq., $600,000,000 shall be made available on October 1, 1990, and shall remain available until expended, and $600,000,000 shall be made available on October 1, 1991, and shall remain available until expended: Provided, That projects selected pursuant to a separate general request for proposals issued pursuant to each of these appropriations shall demon- strate technologies capable of replacing, retrofitting or repowering existing facilities and shall be subject to all provisos contained under this head in Public Laws 99-190, 100-202, and 100-446 as amended by this Act: Provided further, That the general request for proposals using funds becoming available on October 1, 1990, under this paragraph shall be issued no_ later than June 1, 1990, and projects resulting from such a solicitation must be selected no later than February 1, 1991: Provided further, That the general request for proposals using funds becoming available on October 1, 1991, under this paragraph shall be issued no later than September 1, 1991, and projects resulting from such a solicitation must be selected no later than May 1, 1992. The first paragraph under this head in Public Law 100-446 is amended by striking “$575,000,000 shall be made available on October 1, 1989” and inserting “$450,000,000 shall be made available on October 1, 1989, and shall remain available until expended, and $125,000,000 shall be made available on October 1, 1990”: Provided, That these actions are taken pursuant to section 202(b)(1) of Public Law 100-119 (2 U.S.C. 909). With regard to funds made available under this head in this and previous appropriations Acts, unobligated balances excess to the needs of the procurement for which they originally were made available may be applied to other procurements for which requests for proposals have not yet been issued: Provided, That for all procurements for which project selections have not been made as of the date of enactment of this Act no supplemental, backup, or contingent selection of projects shall be made over and above projects originally selected for negotiation and utilization of available funds: Provided further, That reports on projects selected by the Secretary of Energy pursuant to authority granted under this heading which are received by the Speaker of the House of Representatives and the President of the Senate less than 30 legislative days prior to the end of the first session of the 101st Congress shall be deemed to have met the criteria in the third proviso of the fourth paragraph under the heading “Administrative provisions, Department of Energy” in the Department of the Interior and Related Agencies Appropriations Act, 1986, as contained in Public Law 99-190, upon expiration of 30 calendar days from receipt of the report by the Speaker of the House of Representatives and the President of the Senate or at the end of the session, whichever occurs later. Program Update 1999 A-13 Conference Report (H.R. Conf. Rep. No. 264, 101st Cong., Ist Sess. [1987]) CLEAN CoaL TECHNOLOGY Amendment No. 112: Reported in technical disagreement. The managers on the part of the House will offer a motion to recede and concur in the amendment of he Senate which adds the word “replacing” to the definition of clean coal technology. The managers agree that the inclusion of “replacing” for clean coal IV and V is intended to cover the complete replacement of an existing facility if because of design or site specific limitations, repowering or retrofitting of the plant is not a desirable option. Amendment No,. 113: Appropriates $450,000,000 for fiscal year 1990 for clean coal technology instead of $500,000,000 as proposed by the House and $325,000,000 as proposed by he Senate. This appropriation along with $125,000,000 provided for fiscal year 1991 in Amendment 114 fully funds the third round of clean coal technology projects. The managers agree that additional manpower is required, particularly at the Department’s Energy Technology Centers, in order to manage adequately the increased workload from the accumulation of active clean coal technology projects and the inclusion of additional procurements in this bill. Although a legislative floor is not included, the managers agree that at least eighty personnel will be required in addition to the approximately thirty FTE’s now included in the fossil energy research and development appropriation. The managers agree further that funds from the fossil energy research and development appropri- ation should not be used to pay the cost of more than the equivalent FTE’s paid under that account in fiscal year 1989. Amendment No. 114: Reported in technical disagreement. The managers on the part of the House will offer a motion to recede and concur in the amendment of the Senate with an amendment as follows: In lieu of the matter stricken and inserted by said amendment, insert: and shall remain available until expended, and $125,0000,000 The managers on the part of the Senate will move to concur in the amendment of the House to the amendment of the Senate. The amendment provides $125,000,000 in fiscal year 1991 for the third clean coal technology procurement instead of $75,000,000 as proposed by the House and $100,000,000 as proposed by the Senate. A-14 Program Update 1999 Amendment No 115: Deletes Senate proposed appropriation of $150,000,000 for fiscal year 1992 for clean coal technology. The House proposed no such appropriation. Amendment No. 116: Restores House language stricken by the Senate which prohibits the use of supplemental, backup, or contingent project selections in clean coal technology procurements. Amendment No. 117: Restores the word “further” stricken by the Senate. Public Law 101-164 Public Law 101-164, 103 Stat. 1069 (1989) CLEAN CoAL TECHNOLOGY The second paragraph under this head contained in the Act making appropri- ations for the Department of the Interior and Related Agencies for the fiscal year ending September 30, 1990, is amended by striking “$450,000,000” and _ inserting “$419,000,000” and by striking “$125,000,000” and inserting “$156,000,000”. Conference Report (H.R. Conf. Rep. No. 315, 101st Cong., Ist Sess. [1989] The managers have agreed to reduce the funds appropriated by the Energy and Water Development Appropriations Act for Fiscal Year 1990 (Public Law 101-101) for the “Nuclear Waste Disposal Fund” by $46,000,000. This reduction will make funds available for the drug prevention effort. The managers have agreed to reductions to the Interior and Related Agencies Appropriations Act for Fiscal Year 1990 (Public Law 101-121) in order to accom- modate additional drug related appropriations. The reductions are in three areas. The new budget authority for Clean Coal Technology of $450,000,000 for fiscal year 1990 is reduced by $31,000,000 with this same amount added to the advance appropriation for fiscal year 1991. With this change the new amount for fiscal year 1990 is $419,000,000 while fiscal year 1991 increases to $156,000,000. The second area of change is the imposition of an outlay ceiling on Strategic Petroleum Reserve oil acquisition. Outlays will be reduced from an estimated $169,945,000 to $147,125,000 and will decrease the fill rate from approximately 50,000 barrels per day to approximately 46,000 or 47,000 barrels per day. The third reduction relates to the Pennsylvania Avenue Development Corpo- ration. The borrowing authority is reduced from $5,000,000 to $100,000. The conference agreement includes bill language reducing the amount of funds transferred from trust funds to the Health Care Financing Administration Program Management account by $32,000,000 from $1,917,172,000 to $18,851,712,000. This reduction, along with the outlays reserved from the regular 1990 Labor, Health and Human Services, and Education appropriations bill, will be sufficient to support the Subcommittee’s share of the cost of anti-drug abuse funding. The conferees intend that the reduction in trust fund transfers be associated with activities to implement catastrophic health insurance, where funding needs may be diminished. Public Law 101-302 Public Law 101-302, 104 Stat. 213 (1990) CLEAN CoAL TECHNOLOGY Funds previously appropriated under this head for clean coal technology solicitations to be issued no later than June 1, 1990, and no later than September 1, 1991, respectively, shall not be obligated until September 1, 1991: Provided, That the aforementioned solicitations shall not be conducted prior to the ability to obligate these funds: Provided further, That pursuant to section 202(b) of the Balanced Budget and Emergency Deficit Control Reaffirmation Act of 1987, this action is a necessary (but secondary) result of a significant policy change: Provid- ed further, That for the clean coal solicitations identified herein, provisions included for the repayment of government contributions to individual projects shall be identical to those included in the Program Opportunity Notice (PON) for Clean Coal Technology III (CCT-II]) Demonstration Projects (solicitation num- ber DE-PSO1-89 FE 61825), issued by the Department of Energy on May 1, 1989. Conference Report (H.R. Conf. Rep. No. 493, 101st Cong., 2nd Sess. [1990] CLEAN CoaL TECHNOLOGY Amendment No. 89. Reported in technical disagreement. The managers on the part of the House will offer a motion to recede and concur in the amendment of the senate with an amendment as follows: In lieu of the matter proposed by said amendment insert: DEPARTMENT OF ENERGY CLEAN CoAL TECHNOLOGY Funds previously appropriated under this head for clean coal technology solicitations to be issued no later than June 1, 1990, and no later than September 1, 1991, respectively, shall not be obligated until September 1, 1991: Provided, That the aforementioned solicitations shall not be conducted prior to the ability to obligate these funds: Provided further, That pursuant to section 202 (b) of the Balanced Budget and Emergency Deficit Control reaffirmation /Act of 1987 this action is a necessary (but secondary) result of a significant policy change: Provided further, That for the clean coal solicitations identified herein, provisions included for the repayment of government contributions to individual projects shall be identical to those included in the Program Opportunity Notice (PON) for Clean Coal Technology III (CCT-IIl) Demonstration Projects (solicitation number DE-PS01-89 FE 61825), issued by the Department of Energy on May 1, 1989. The managers on the part of the Senate will move to concur in the amendment of the House to the amendment of the Senate. The amendment delays the fourth and fifth clean coal technology solicitations as proposed by the Senate and specifies that, when issued, these solicitations must use repayment provisions used successfully in the third solicitation. This provision was included in the House introduced bill (H.R. 4828) and modifies a Senate amendment to the original Dire Emergency Supplemental. The managers agree that changes to the clean air bill, proposed by a House authorizing committee, that would modify the clean coal technology program must be resolved before a reasonable solicitation can be issued. The proposed delay will allow such resolution. Program Update 1999 A-15 The managers have added language to ensure that provisions dealing with the repayment of government provided funds will remain the same as the third round of procurements. These provisions were developed over a four year period based on experience of previous procurements and negotiations, and input from industrial participants, Congress, and the managers of the program. They appear to be working well. Based on the long-term experience, and the clear fact that implementation of this type of technology will become even more important with passage of clean air legislation, the managers reject proposals put forth by the Department of Energy to increase rates substantially. Such proposals, while they might increase the recovery of government-provided funds over periods of up to 20 years, might also act as a deterrent to industrial participation in the program, which is already over 50 percent cost-shared by industry. The purpose of the program is to accelerate the introduction of clean uses of coal in a more efficient manner in compliance with stringent new air quality standards, not the provision of investment returns to the Government at the expense of nascent markets. Public Law 101-512 Public Law 101-512, 104 Stat. 1915 (1990) CLEAN CoAL TECHNOLOGY The first paragraph under this head in Public Law 101-121 is amended by striking “$600,000,000 shall be made available on October 1, 1990, and shall remain available until expended, and $600,000,000 shall be made available on October 1, 1991, and shall remain available until expended” and inserting “$600,000,000 shall be made available as follows: $35,000,000 on September 1, 1991, $315,000,000 on October 1, 1991, and $250,000,000 on October 1, 1992, all such sums to remain available until expended for use in conjunction with a separate general request for proposals, and $600,000,000 shall be made available as follows: $150,000,000 on October 1, 1991, $225,000,000 on October 1, 1992, and $225,000,000 on October 1, 1993, all such sums to remain available until expended for use in conjunction with a separate general request for proposals”: Provided, That these actions are taken A-16 Program Update 1999 pursuant to section 202(b)(1) of Public Law 100-119 (2 U.S.C. 909): Provided further, That a fourth general request for proposals shall be issued not later than February 1, 1991, and a fifth general request for proposals shall be issued not later than March 1, 1992: Provided further, That project proposals resulting from such solicitations shall be selected not later than eight months after the date of the general request for proposals: Provided further, That for clean coal solicitations required herein, provisions included for the repayment of government contributions to individual projects shall be identical to those included in the Program Opportunity Notice (PON) for Clean Coal Technology III (CCT-II]) Demonstration Projects (solicitation number DE-PS01-89 FE 61825), issued by the Department of Energy on May 1, 1989: Provided further, That funds provided under this head in this or any other appropriations Act shall be expended only in accordance with the provisions governing the use of such funds contained under this head in this or any other appropriations Act. With regard to funds made available under this head in this and previous appropriations Acts, unobligated balances excess to the needs of the procurement for which they originally were made available may be applied to other procurements for use on projects for which cooperative agreements are in place, within the limitations and proportions of Government financing increases currently allowed by law: Provided, That the Department of Energy, for a period of up to five (5) years after completion of the operations phase of a cooperative agreement may provide appro- priate protections, including exemptions from subchapter II of chapter 5 of title 5, United States Code, against the dissemination of information that results from demonstration activities conducted under the Clean Coal Technology Program and that would be a trade secret or commercial or financial information that is privileged or confidential if the information had been obtained from and first produced by a non- Federal party participating in a Clean Coal Technology project: Provided further, That, in addition to the full-time permanent Federal employees specified in section 303 of Public Law 97-257, as amended, no less than 90 full-time Federal employees shall be assigned to the Assistant Secretary for Fossil Energy for carrying out the programs under this head using funds available under this head in this and any other appropriations Act and of which 35 shall be for PETC and 30 shall be for METC: Provided further, That reports on projects selected by the Secretary of Energy pursuant to authority granted under this heading which are received by the Speaker of the House of Representatives and the President of the Senate less than 30 legislative days prior to the end of the second session of the 101st Congress shall be deemed to have met the criteria in the third proviso of the fourth paragraph under the heading “Administrative provisions, Department of Energy” in the Department of the Interior and Related Agencies Appropriations Act, 1986, as contained in Public Law 99-190, upon expiration of 30 calendar days from receipt of the report by the Speaker of the House of Representatives and the President of the Senate or at the end of the session, whichever occurs later. Conference Report (H.R. Conf. Rep. No. 971, 101st Cong., 2nd Sess. [1990)) CLEAN CoAL TECHNOLOGY Amendment No. 142: Provides $35,000,000 for clean coal technology on September 1, 1991 as proposed by the House instead of $100,000,000 as proposed by the Senate. This amendment and Amendment No. 143 shift the availability of $65,000,000 from fiscal year 1991 to fiscal year 1992. Amendment No. 143: Provides $315,000,000 for clean coal technology on October 1, 1991 as proposed by the House instead of $250,000,000 as proposed by the Senate. This amendment and Amendment No. 142 shift the availability of $65,000,000 from fiscal year 1991 to fiscal year 1992. Amendment No. 144: Provides dates for two solicitations for clean coal technology as proposed by the Senate. The date for CCT-IV is amended to February 1, 1991 from January 1, 1991. The date for CCT-V is not changed from the Senate date of March 1, 1992. The managers have agreed to a February 1, 1991 date for the next solicitation to enable the Department to publish a draft solicitation for comment by interested parties. It is expected that there will be changes to evaluation criteria and other factors that make it imperative that potential proposers have an opportunity to comment on the content of the solicitation. The managers urge the Department to include potential benefits to remote, import-dependent sites as a program policy factor in evaluating proposals. The Department should also consider projects which can provide multiple fuel resource options for regions which are more than seventy-five percent dependent on one fuel form for total energy requirements. Amendment No. 145: Requires selection of projects within eight months of the requests for proposals required by Amendment No. 144 as proposed by the Senate. The House had no such provision. Amendment No. 146: Requires repayment of government contributions to projects under conditions identical to the most recent clean coal solicitation as proposed by the Senate. The House had no such provision. Amendment No. 147: Provides that funds for clean coal technology may be expended only under conditions contained in appropriations Acts. The Senate language had prohibited geographic restrictions on the expenditure of funds. The House had no such provision. The managers direct that no preferential consideration be given to any project referenced explicitly or implicitly in other legislation. The managers agree to delete bill language dealing with geographic restrictions based on such restrictions being deleted from clean air legislation. Amendment No. 148: Earmarks employees to two fossil energy technology centers as proposed by the Senate. The House had no such provision. The managers agree that the earmarks for PETC and METC are minimum levels and may be increased as necessary. The managers agree that no more than the current 30 full-time equivalent positions from fossil energy research and development may be used in the clean coal program in fiscal year 1991. Public Law 102-154 Public Law 102-154, 105 Stat. 990 (1991) CLEAN CoAL TECHNOLOGY The first paragraph under this head in Public Law 101-512 is amended by striking the phrase “$150,000,000 on October 1, 1991, $225,000,000 on October 1, 1992” and inserting “$100,000,000 on October 1, 1991, $275,000,000 on October 1, 1992”. Notwithstanding the issuance date for the fifth general request for proposals under this head in Public Law 101-512, such request for proposals shall be issued not later than July 6, 1992, and notwithstanding the proviso under this head in Public Law 101-512 regarding the time interval for selection of proposals resulting from such solicitation, project proposals resulting from the fifth general request for proposals shall be selected not later than ten months after the issuance date of the fifth Program Update 1999 A-17 general request for proposals: Provided, That hereafter the fifth general request for proposals shall be subject to all provisos contained under this head in previous appropriations Acts unless amended by this Act. Notwithstanding the provisos under this head in previous appropriations Acts, projects selected pursuant to the fifth general request for proposals shall advance significantly the efficiency and environmental performance of coal-using technolo- gies and be applicable to either new or existing facilities: Provided, That budget periods may be used in lieu of design, construction, and operating phases for cost- sharing calculations: Provided further, That the Secretary shall not finance more than 50 per centum of the total costs of any budget period: Provided further, That project specific development activities for process performance definition, compo- nent design verification, materials selection, and evaluation of alternative designs may be funded on a cost-shared basis up to a limit of 10 per centum of the Government’s share of project cost: Provided further, That development activities eligible for cost-sharing may include limited modifications to existing facilities for project related testing but do not include construction of new facilities. With regard to funds made available under this head in this and previous appropriations Acts, unobligated balances excess to the needs of the procurement for which they originally were made available may be applied to other procurements for use on projects for which cooperative agreements are in place, within the limitations and proportions of Government financing increases currently allowed by law: Provided, That hereafter, the Department of Energy, for a period of up to five years after completion of the operations phase of a cooperative agreement may provide appropriate protections, including exemptions from subchapter II of chapter 5 of title 5, United States Code, against the dissemination of information that results from demonstration activities conducted under the Clean Coal Technology Program and that would be a trade secret or commercial or financial information that is privileged or confidential if the information had been obtained from and first produced by a non- Federal party participating in a Clean Coal Technology project: Provided further, That hereafter, in addition to the full-time permanent Federal employees specified in section 303 of Public Law 97-257, as amended, no less than 90 full-time Federal employees shall be assigned to the Assistant Secretary for Fossil Energy for carrying out the programs under this head using funds available under this head in this and any other appropriations Act and of which not less than 35 shall be for PETC and not less than 30 shall be for METC: Provided further, That hereafter reports on projects selected by the Secretary of Energy pursuant to authority granted under this heading A-18 — Program Update 1999 which are received by the Speaker of the House of Representatives and the President of the Senate less than 30 legislative days prior to the end of each session of Congress shall be deemed to have met the criteria in the third proviso of the fourth paragraph under the heading “Administrative provisions, Department of Energy” in the Department of the Interior and Related Agencies Appropriations Act, 1986, as contained in Public Law 99-190, upon expiration of 30 calendar days from receipt of the report by the Speaker of the House of Representatives and the President of the Senate or at the end of the session, whichever occurs later. Conference Report (H.R. Conf. Rep. No. 256, 102nd Cong., Ist Sess. (1991) CLEAN CoAL TECHNOLOGY Amendment No. 165: Reported in technical disagreement. The managers on the part of the House will offer a motion to recede and concur in the amendment of the Senate with an amendment as follows: In lieu of the matter stricken and inserted by said amendment insert: Notwithstanding the issuance date for the fifth general request for proposals under this head in Public Law 101-512, such request for proposals shall be issued not later than July 6, 1992, and notwithstanding the proviso under this head in Public Law 101-512 regarding the time interval for selection of proposals resulting from such solicitation, project proposals resulting from the fifth general request for proposals shall be selected not later than ten months after the issuance date of the fifth general request for proposals: Provided, That hereafter the fifth general request for proposals The managers on the part of the Senate will move to concur in the amendment of the House to the amendment of the Senate. The amendment changes the issuance date for the fifth general request for proposals to July 6, 1992 instead of March 1, 1992 as proposed by the House and August 10, 1992 as proposed by the Senate and the allowable length of time from issuance of the request for proposals to selection of projects to ten months. The amendment also deletes Senate proposed bill language pertaining to a sixth general request for proposals as discussed below. The managers agree that the additional two months in the procurement process for the fifth round of proposals should include an additional month to allow for the preparation of proposals by the private sector, and up to an additional month for Department of Energy review and evaluation of proposals when compared to the process for the fourth round. The managers have agreed to delete bill language regarding a sixth round of proposals, but agree that funding will be provided for a sixth round based on unobligated and unneeded amounts that may become available from the first five rounds. The report from the Secretary on available funds, which was originally in the Senate amendment, is still a requirement and such report should be submitted to the House and Senate Committees on Appropriations not later than May 1, 1994. Based on that report, the funding, dates and conditions for the sixth round will be included in the fiscal year 1995 appropriation. The managers expect that the fifth solicitation will be conducted under the same general types of criteria as the fourth solicitation principally modified only (1) to include the wider range of eligible technologies or applications; (2) to adjust technical criteria to consider allowable development activities, to strengthen criteria for non-utility demonstrations, and to adjust commercial performance criteria for additional facilities and technologies with regard to aspects of general energy efficiency and environmental performance; and (3) to clarify and strengthen cost and finance criteria particularly with regard to development activities. Amendment No. 166: Restores House language deleted by the Senate which refers to a fifth general request for proposals. The Senate proposed language dealing with both a fifth and a sixth round. Amendment No. 167: Reported in technical disagreement. The managers on the part of the House will offer a motion to recede and concur in the amendment of the Senate which directs the Secretary of Energy to reobligate up to $44,000,000 from the fourth round of Clean Coal Technology proposals to a proposal ranked highest in its specific technology category by the Source Evaluation Board if other than the highest ranking project in that category was selected originally by the Secretary, and if such funds become unobligated and are sufficient to fund such projects. This amendment would earmark such funds, if they become available, to a specific project not chosen in the Department of Energy selection process for the fourth round of Clean Coal Technology. Amendment No. 168: Technical amendment which deletes House proposed punctuation and numbering as proposed by the Senate. Amendment No. 169: Deletes House proposed language which made unobligat- ed funds available for procurements for which requests for proposals have not been issued. Amendment No. 170: Reported in technical disagreement. The managers on the part of the House will offer a motion to recede and concur in the amendment of the Senate which adds “not less than” to employment floor language for PETC as proposed by the Senate. The House had no such language. Amendment No. 171: Reported in technical disagreement. The managers on the part of the House will offer a motion to recede and concur in the amendment of the Senate which adds “not less than” to employment floor language for METC as proposed by the Senate. The House had no such language. Public Law 102-381 Public Law 102-381, 106 Stat. 1374 (1992) CLEAN COAL TECHNOLOGY The first paragraph under this head in Public Law 101-512, as amended, is further amended by striking the phrase “and $250,000,000 on October 1, 1992” and inserting “$150,000,000 on October 1, 1993, and $100,000,000 on October 1, 1994” and by striking the phrase “$275,000,000 on October 1, 1992, and $225,000,000 on October 1, 1993” and inserting “$250,000,000 on October 1, 1993, and $250,000,000 on October 1, 1994”. Program Update 1999 A-19 Public Law 103-138 Public Law 103-138, 107 Stat. 1379 (1993) CLEAN CoAL TECHNOLOGY The first paragraph under this head in Public Law 101-512, as amended, is further amended by striking the phrase “$150,000,000 on October 1, 1993, and $100,000,000 on October 1, 1994” and inserting “$100,000,000 on October I, 1993, $100,000,000 on October 1, 1994, and $50,000,000 on October 1, 1995” and by striking the phrase “$250,000,000 on October 1, 1993, and $250,000,000 on October 1, 1994” and inserting “$125,000,000 on October 1, 1993, $275,000,000 on October 1, 1994, and $100,000,000 on October 1, 1995”. Public Law 103-332 Public Law 103-332, 108 Stat. 2499 (1994) CLEAN CoAL TECHNOLOGY The first paragraph under this head in Public Law 101-512, as amended, is further amended by striking the phrase “$100,000,000 on October 1, 1994, and $50,000,000 on October 1, 1995” and inserting “$18,000,000 on October 1, 1994, $100,000,000 on October 1, 1995, and $32,000,000 on October 1, 1996”; and by striking the phrase “$275,000,000 on October 1, 1994, and $100,000,000 on October 1, 1995” and inserting “$19,121,000 on October 1, 1994, $100,000,000 on October 1, 1995, and $255,879,000 on October 1, 1996”: Provided, That not to exceed $18,000,000 available in fiscal year 1995 may be used for administrative oversight of the Clean Coal Technology program. A-20 Program Update 1999 Public Law 104-6 Public Law 104-6, 109 Stat. 73 (1995) CLEAN CoAL TECHNOLOGY (RESCISSION) Of the funds made available under this heading for obligation in fiscal year 1996, $50,000,000 are rescinded and of the funds made available under this heading for obligation in fiscal year 1997, $150,000,000 are rescinded: Provided, That funds made available in previous appropriations Acts shall be available for any ongoing project regardless of the separate request for proposal under which the project was selected. Public Law 104-134 Conference Report (H.R. Conf. Rep. No. 402, 104th Cong., Ist Sess. (1995) The managers do not object to the use of up to $18,000,000 in clean coal technology program funds for administration of the clean coal program. Public Law 104-208 Public Law 104-208, 110 Stat. 3009 (1999) CLEAN CoAL TECHNOLOGY (RESCISSION) Of the funds made available under this heading for obligation in fiscal year 1997 or prior years, $123,000,000 are rescinded: Provided, That funds made available in previous appropriations Acts shall be available for any ongoing project regardless of the separate request for proposal under which the project was selected. Conference Report (H.R. Conf. Rep. No. 863, 104th Cong., 2nd Sess., [1996)) CLEAN CoAL TECHNOLOGY (RESCISSION) Of the funds made available under this heading for obligation in fiscal year 1997 or prior years, $123,000,000 are rescinded: Provided, That funds made available in previous appropriations Acts shall be available for any ongoing project regardless of the separate request for proposal under which the project was selected. Senate Report (S. Rep. No. 319, 104th Cong., 2nd Sess. [1996]) The Committee does not object to the use of up to $16,000,000 in available funds for administration of the clean coal program in fiscal year 1997. House Report (H.R. Rep. No. 625, 104th Cong., 2nd Sess. [1996]) The Committee does not object to the use of up to $16,000,000 in available funds for administration of the clean coal program in fiscal year 1997. Public Law 105-18 Public Law 105-18, 111 Stat. 158 (1997) CLEAN COAL TECHNOLOGY (RESCISSION) Of the funds made available under this heading for obligation in fiscal year 1997 or prior years, $17,000,000 are rescinded: Provided, That funds made available in previous appropriations Acts shall be available for any ongoing project regardless of the separate request for proposal under which the project was selected. Public Law 105-83 Public Law 105-83, 111 Stat. 37 (1997) Of the funds made available under this heading for obligation in fiscal year 1997 or prior years, $101,000,000 are rescinded: Provided, That funds made available in previous appropriations Acts shall be available for any ongoing project regardless of the separate request for proposal under which the project was selected. Program Update 1999 A-21 Public Law 105-277 Public Law 105-277, 112 Stat. 2681 (1998) CLEAN CoAL TECHNOLOGY (DEFERRAL) Of the funds made available under this heading for obligation in prior years, $10,000,000 of such funds shall not be available until October 1, 1999; $15,000,000 shall not be available until October 1, 2000; and $15,000,000 shall not be available until October 1, 2001: Provided, That funds made available in previous appropriations Acts shall be available for any ongoing project regardless of the separate request for proposal under which the project was selected. Conference Report (H.R. Conf. Rep. No. 825, 105th Cong. 2nd Sess. [1998] CLEAN CoAL TECHNOLOGY The conference agreement provides for the deferral of $40,000,000 in previ- ously appropriated funds for the clean coal technology program as proposed by the Senate. The House did not propose to defer funding. The Committees agree that $14,900,000 may be used for administration of the clean coal technology program. A-22 Program Update 1999 Public Law 106-113 Public Law 106-113, Stat.___ (1999) CLEAN CoAL TECHNOLOGY (DEFERRAL) Of the funds made available under this heading for obligation in prior years, $156,000,000 shall not be available until October 1, 2000: Provided, That funds made available in previous appropriations Acts shall be available for any ongoing project regardless of the separate request for proposal under which the project was selected. Conference Report (H.R. Rep. No. 406, 106th Cong., Ist Sess. [1999]) CLEAN Coat TECHNOLOGY (DEFERRAL) The conference agreement provides for the deferral of $156,000,000 in previous- ly appropriated funds for the clean coal technology program as proposed by the Senate instead of a deferral of $256,000,000 as proposed by the House. The managers agree that up to $14,400,00 may be used for program direction. Appendix B: Program History Solicitation History The objective of the CCT-I solicitation, issued February 17, 1986, was to seek cost-shared projects to demonstrate the feasibility of clean coal technologies for commercial applications. The Program Opportu- nity Notice (PON) elicited 51 proposals. Nine projects were selected and 14 projects were placed on a list of alternatives in the event negotiations on the original 9 projects were unsuccessful; 8 alternate projects were eventually selected as replacement projects. Projects were selected from the list of alternates on three separate occasions. The CCT-II PON, issued February 22, 1988, solicited cost-shared, innovative clean coal technolo- gy projects to demonstrate technologies that were capable of being commercialized in the 1990s, more cost-effective than current technologies, and capable of achieving significant reductions in SO, and/or NO, emissions from existing coal-burning facilities, particularly those that contribute to transboundary air pollution. The CCT-II PON was the first solicitation implementing the recommendations of the U.S. and Canadian Special Envoys’ report on acid rain. DOE received 55 proposals and selected 16 as best further- ing the goals and objectives of the PON (no alternates were selected). The objective of the CCT-III PON, issued May 1, 1989, was to solicit cost-shared clean coal technology projects to demonstrate innovative, energy-efficient technologies capable of being commercialized in the 1990s. These technologies were to be capable of (1) achieving significant reductions in emissions of SO, and/or NO, from existing facilities to minimize environmental impacts, such as transboundary and interstate air pollution; and/or (2) providing for future energy needs in an environmentally acceptable manner. DOE received 48 proposals and selected 13 projects as best furthering the goals and objectives of the PON. The CCT-IV PON, issued January 17, 1991, solicited proposals to conduct cost-shared clean coal technology projects to demonstrate innovative, energy-efficient, economically competitive technolo- gies. These technologies were to be capable of (1) retrofitting, repowering, or replacing existing facili- ties while achieving significant reductions in the emissions of SO,, NO,, or both, and/or (2) providing for future energy needs in an environmentally accept- able manner. A total of 33 proposals were submitted in response to the PON. Nine projects were selected. The objective of the CCT-V PON, issued July 6, 1992, was to solicit proposals to conduct cost-shared demonstration projects that significantly advance the efficiency and environmental performance of coal- using technologies and are applicable to either new or existing facilities. In response to the solicitation, DOE received proposals for 24 projects and selected 5 projects. Selection and Negotiation History The following is a history of the selection and negotiations for the CCT Program Projects. Data are provided through September 1999. July 1986 Nine projects were selected under CCT-I (14 alter- nate projects selected to replace any selected projects if negotiations were unsuccessful). March 1987 DOE signed cooperative agreements with two CCT-I participants, Coal Tech Corporation (Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control) and The Ohio Power Company (Tidd PFBC Demonstration Project). June 1987 DOE signed a cooperative agreement with CCT-I participant, The Babcock & Wilcox Company (now McDermott Technology, Inc.) LIMB Demonstration Project Extension and Coolside Demonstration. Program Update 1999 B-1 July 1987 DOE signed a cooperative agreement with CCT-I participant, Energy and Environmental Research Corporation (Enhancing the Use of Coals by Gas Reburning and Sorbent Injection). September 1987 General Electric Company withdrew its proposal (Integrated Coal Gasification Steam Injection Gas Turbine Demonstration Plants with Hot Gas Cleanup). October 1987 Weirton Steel Corporation withdrew its proposal, Direct Iron Ore Reduction to Replace Coke Oven/Blast Furnace for Steelmaking, from further consideration. Four more CCT-I projects were selected: Colorado-Ute Electric Association, Inc. (Nucla CFB Demonstration Project); TRW, Inc. (Advanced Slagging Coal Combustor Utility Demonstration Project); Minnesota Department of Natural Resources (COREX Ironmaking Demonstration Project); and Foster Wheeler Power Systems, Inc. (Clean Energy IGCC Demonstration Project). December 1987 DOE signed cooperative agreements with two more CCT-I participants, Ohio Ontario Clean Fuels, Inc., (Prototype Commercial Coal/Oil Coprocessing Project) and Energy International, Inc. (Underground Coal Gasification Demonstration Project). B-2 Program Update 1999 January 1988 DOE signed a cooperative agreement with The M.W. Kellogg Company and Bechtel Development Company for a CCT-I project, The Appalachian IGCC Demon- stration Project. September 1988 Sixteen projects were selected under CCT-II. November 1988 DOE signed a cooperative agreement with CCT-I participant, TRW, Inc. (Advanced Slagging Coal Combustor Utility Demonstration Project). December 1988 Negotiations were terminated with Minnesota Department of Natural Resources (COREX Ironmaking Demonstration Project) under CCT-I. DOE selected three more CCT-I projects: ABB Combustion Engineering, Inc. and CQ Inc. (Develop- ment of the Coal Quality Expert™); Western Energy Company (formerly Rosebud SynCoal Partnership, now Western SynCoal LLC; Advanced Coal Conver- sion Process Demonstration); and United Coal Company (Coal Waste Recovery Advanced Technol- ogy Demonstration). June 1989 The City of Tallahassee CCT-I project, ACFB Repow- ering, was selected from the alternate list. The M.W. Kellogg Company and Bechtel Develop- ment Company withdrew their CCT-I project, Clean Energy IGCC Demonstration Project. September 1989 United Coal Company withdrew its CCT-I project, Coal Waste Recovery Advanced Technology Demonstration. November 1989 DOE signed a cooperative agreement with CCT-II participant, Bethlehem Steel Corporation (Innovative Coke Oven Gas Cleaning System for Retrofit Applications). Combustion Engineering, Inc., (CCT-II) withdrew its Postcombustion Sorbent Injection Demonstration Project. December 1989 Thirteen projects were selected under CCT-III. DOE signed cooperative agreements with five CCT- II participants: ABB Combustion Engineering, Inc. (SNOX™ Flue Gas Cleaning Demonstration Project); The Babcock & Wilcox Company (SO, -NO, -Rox Box™ Flue Gas Cleanup Demonstration Project); Passama- quoddy Tribe (Cement Kiln Flue Gas Recovery Scrubber); Pure Air on the Lake, L.P. (Advanced Flue Gas Desulfurization Demonstration Project); and Southern Company Services, Inc. (Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler). Energy International, Inc., withdrew its CCT-I project, Underground Coal Gasification Demonstration Project. February 1990 Foster Wheeler Power Systems, Inc., withdrew its CCT-I proposal, Clean Energy IGCC Demonstration Project. April 1990 DOE signed cooperative agreements with three CCT- II participants: The Appalachian Power Company (PFBC Utility Demonstration Project); The Babcock & Wilcox Company (Demonstration of Coal Reburning for Cyclone Boiler NO, Control); and Southern Company Services, Inc. (Demonstration of Innovative Applications of Technology for the CT-121 FGD Process). June 1990 DOE signed cooperative agreements with the co- participants of one CCT-I project, ABB Combustion Engineering, Inc. and CQ Inc. (Development of the Coal Quality Expert™), and with two CCT-II participants: Southern Company Services, Inc. (Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers) and TransAlta Resources Investment Corporation (LNS Burner for Cyclone-Fired Boilers Demonstration Project). September 1990 DOE signed cooperative agreements with one CCT-I participant, Western Energy Company (formerly Rosebud SynCoal Partnership, now Western SynCoal LLC); Advanced Coal Conversion Process Demon- stration); one CCT-II participant, Southern Company Services, Inc. (180-MWe Demonstration of Advanced Tangentially-Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers); and one CCT-III participant, ENCOAL Corporation (ENCOAL*® Mild Coal Gasification Project). Negotiations were terminated with CCT-II participant, Southwestern Public Service Company (Nichols CFB Repowering Project). October 1990 DOE signed cooperative agreements with four CCT- III participants: AirPol, Inc. (10-MWe Demonstration of Gas Suspension Absorption); The Babcock & Wilcox Company (Full-Scale Demonstration of Low- NO, Cell Burner Retrofit); Bechtel Corporation (Confined Zone Dispersion Flue Gas Desulfurization Demonstration); and Energy and Environmental Research Corporation (Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler). November 1990 DOE signed cooperative agreements with one CCT-I participant, The City of Tallahassee (Arvah B. Hopkins Circulating Fluidized-Bed Repowering Project; now JEA and the JEA Large-Scale CFB Combustion Demonstration Project); one CCT-II participant, ABB Combustion Engineering, Inc. (Combustion Engineering IGCC Repowering Project); and two CCT-III participants, Bethlehem Steel Corporation (Blast Furnace Granular-Coal Injection System Demonstration Project) and LIFAC-North America (LIFAC Sorbent Injection Desulfurization Demonstration Project). December 1990 Negotiations terminated with CCT-II participant, Otisca Industries, Ltd. (Otisca Fuel Demonstration Project)andCPICOR. March 1991 DOE signed cooperative agreements with three CCT- III participants: MK-Ferguson Company (now NOXSO Corporation (Commercial Demonstration of the NOXSOSO,/NO, Removal Flue Gas Cleanup System); Public Service Company of Colorado (Integrated Dry NO//SO, Emissions Control System); and Tampa Electric Company (formerly Clean Power Cogeneration Limited Partnership; now Tampa Electric Integrated Gasification Combined-Cycle Project. TRW, Inc., withdrew its CCT-I project (Advanced Slagging Coal Combustion Utility Demonstration Project). April 1991 DOE signed a cooperative agreement with CCT-III participant, Alaska Industrial Development and Export Authority (Healy Clean Coal Project). June 1991 DOE withdrew its sponsorship of the Ohio Ontario Clean Fuels, Inc., CCT-I project, Prototype Commercial Coal/Oil Coprocessing Plant. August 1991 DOE signed a cooperative agreement with CCT-III participant, DMEC-1 Limited Partnership (formerly Dairyland Power Cooperative; PCFB Demonstration Project). TransAlta Resources Investment Corporation withdrew its CCT-II project, LNS Burner for Cyclone- Fired Boilers Demonstration Project. Program Update 1999 B-3 September 1991 Nine projects were selected under CCT-IV. Coal Tech Corporation’s CCT-I project, Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control, final reports issued and project com- pleted. April 1992 Tri-State Generation and Transmission Association, Inc.’s (formerly Colorado-Ute Electric Association, Inc.) CCT-I project, Nucla CFB Demonstration Project, final reports issued and project completed. June 1992 The City of Tallahassee project (CCT-1) was restruc- tured and transferred to York County Energy Partners, L.P. (York County Energy Partners Cogeneration Project). July 1992 DOE signed cooperative agreements with two CCT- IV participants: Tennessee Valley Authority (now New York State Electric & Gas Corporation; Micron- ized Coal Reburning Demonstration for NO, Control ona 175-MWe Wall-Fired Unit), and the Wabash River Coal Gasification Repowering Project Joint Venture (Wabash River Coal Gasification Repowering Project). August 1992 DOE signed a cooperative agreement with CCT-IV participant, Sierra Pacific Power Company (Pifion Pine IGCC Power Project). B-4 Program Update 1999 Cordero Mining Company withdrew from negotiations for its CCT-IV project, Cordero Coal-Upgrading Demonstration Project. At the participant’s request, Union Carbide Chemicals and Plastics Company Inc. (CCT-IV) was granted an extension of one year to the DOE deadline for com- pleting negotiations of its Demonstration of the Union Carbide CANSOLVT System at the Alcoa Generating Corporation Warrick Power Plant. October 1992 DOE signed cooperative agreements with one CCT- III participant, Air Products and Chemicals, Inc. (Commercial-Scale Demonstration of the Liquid Phase Methanol [LPMEOH™ Process) and with four CCT- IV participants: Custom Coals International (Self- Scrubbing Coal™: An Integrated Approach to Clean Air); New York State Electric & Gas Corporation (Milliken Clean Coal Technology Demonstration Project); TAMCO Power Partners (Toms Creek IGCC Demonstration Project); and ThermoChem, Inc. (Pulse Combustor Design Qualification Test). November 1992 The Babcock & Wilcox Company’s (now McDermott Technology, Inc.) CCT-I project, LIMB Demonstration Project Extension and Coolside Demonstration, final reports issued and project completed. May 1993 Five projects were selected under CCT-V: Four Rivers Energy Partners, L.P. (Four Rivers Energy Moderniza- tion Project (formerly Calvert City Advanced Energy Project, now McIntosh Unit 4B Topped PCFB Demonstration Project); Duke Energy Corporation (Camden Clean Energy Demonstration Project); Centerior Energy Corporation, on behalf of CPICOR™ Management Company L.L.C. (Clean Power from Integrated Coal/Ore Reduction [CPICOR™]); Arthur D. Little, Inc. (Clean Coal Combined-Cycle Project; formerly Demonstration of Coal Diesel Technology at Easton Utilities; now Clean Coal Diesel Demonstration Project); and Pennsylvania Electric Company (Warren Station Externally Fired Combined-Cycle Demonstra- tion Project). July 1993 Union Carbide Chemicals and Plastics Company, Inc., withdrew its CCT-IV proposal, Demonstration of the Union Carbide CANSOLVT System at the Alcoa Generating Corporation Warrick Power Plant. February 1994 The Passamaquoddy Tribe’s CCT-III project, Cement Kiln Flue Gas Recovery Scrubber, final reports issued and project completed. March 1994 The Babcock & Wilcox Company’s CCT-II project, Demonstration of Coal Reburning for Cyclone Boiler NO, Control, final reports issued and project completed. June 1994 DOE signed a cooperative agreement with CCT-V participant, Arthur D. Little, Inc. (Coal Diesel Com- bined-Cycle Project). Southern Company Services’ CCT-III project, 180- MWe Demonstration of Advanced Tangentially- Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers, final reports issued and project completed. Bechtel Corporation’s CCT-III project, Confined Zone Dispersion Flue Gas Desulfurization Demonstration, final reports issued and project completed. August 1994 DOE signed cooperative agreements with two CCT- V participants, Four Rivers Energy Partners, L.P. (Four Rivers Energy Modernization Project); and Pennsylva- nia Electric Company ( Warren Station Externally-Fired Combined-Cycle Demonstration Project). The CCT-III project, Commercial Demonstration of the NOXSOSO,/NO, Removal Flue Gas Cleanup System, was relocated and transferred to NOXSO Corporation. September 1994 The Air Products and Chemicals CCT-III project, Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process, was transferred to Air Products Liquid Phase Conversion Company, L.P. December 1994 DOE signed a cooperative agreement with CCT-V participant, Clean Energy Partners Limited Partnership (formerly Duke Energy Corporation; Clean Energy Demonstration Project; now Kentucky Pioneer IGCC Demonstration Project). March 1995 TAMCO Power Partner’s CCT-IV project, Toms Creek IGCC Demonstration Project, was not granted a further extension and the project was concluded. April 1995 Bethlehem Steel Corporation’s CCT-II project, Innovative Coke Oven Gas Cleaning System for Retrofit Applications, was terminated by mutual agreement with DOE because coke production was suspended at the demonstration facility. June 1995 AirPol, Inc.’s CCT-II project, 10-MWe Demonstration of Gas Suspension Absorption, final reports issued and project completed. September 1995 The Babcock & Wilcox Company’s CCT-II project, SO - NO, -Rox Box™ Flue Gas Cleanup Demonstration Project, final reports issued and project completed. December 1995 The Tennessee Valley Authority and New York State Electric & Gas Corporation finalized an agreement to allow the project, Micronized Coal Reburning Demon- stration for NO, Control, to be conducted at both Milliken Station in Lansing, NY and Eastman Kodak Company in Rochester, NY. The Babcock & Wilcox Company’s CCT-II project, Full-Scale Demonstration of Low-NO, Cell Burner Retrofit, final reports issued and project completed. The Ohio Power Company’s CCT-I project, Tidd PFBC Demonstration Project, final reports issued and project completed. May 1996 The ABB Combustion Engineering, Inc. CCT-II project, Combustion Engineering IGCC Repowering Project, was concluded. June 1996 Pure Air on the Lake’s CCT-II project, Advanced Flue Gas Desulfurization Project, final reports issued and project completed. August 1996 The Arthur D. Little, Inc., CCT-V project was restruc- tured and retitled as the Clean Coal Diesel Demonstra- tion Project. September 1996 The Appalachia Power Company CCT-II project, PFBC Utility Demonstration Project, was concluded. Program Update 1999 B-5 October 1996 DOE signed a cooperative agreement with CCT-V participant, CPICOR™ Management Company L.L.C. (Clean Power from Integrated Coal/Ore Reduction [CPICOR™)). November 1996 Southern Company Services’ CCT-II project, Demon- stration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers, final reports issued and project completed. December 1996 ABB Environmental Systems’ CCT-II project, SNOX™ Flue Gas Cleaning Demonstration Project, final reports issued and project completed. May 1997 The Pennsylvania Electric Company CCT-V project, Externally Fired Combined-Cycle Demonstration Project, was concluded. September 1997 DOE modified the cooperative agreement for JEA’s (formerly Jacksonville Electric Authority) CCT-I project, JEA Large-Scale CFB Combustion Project (formerly The City of Tallahassee project, then the York County Energy Partners project). December 1997 ENCOAL Corporation’s CCT-III project, ENCOAL” Mild Coal Gasification Project, final reports issued and project completed. B-6 Program Update 1999 DOE signed a new cooperative agreement for the restructured City of Lakeland’s CCT-III project, MelIntosh Unit 4A PCFB Demonstration Project (formerly the DMEC-1 Limited Partnership project). January 1998 DOE signed a new cooperative agreement for the restructured City of Lakeland’s CCT-III project, McIntosh Unit 4B Topped PCFB Demonstration Project (formerly the Four Rivers Energy Partners, L.P. project). April 1998 LIFAC-North America’s CCT-III project, LIFAC Sorbent Injection Desulfurization Demonstration Project, final reports issued and project completed. June 1998 Southern Company Services’ CCT-II project, Demon- stration of Innovative Applications of Technology for the CT-121 FGD Process, final reports issued and project completed. The ABB Combustion Engineering, Inc. and CQ Inc.’s CCT-I project, Development of the Coal Quality Expert™, final reports issued and project completed. September 1998 Energy and Environmental Research Corporation’s CCT-I project, Enhancing the Use of Coals by Gas Reburning and Sorbent Injection, final reports issued and project completed. DOE signed a revised cooperative agreement for the restructured ThermoChem Inc.’s CCT IV project, Pulse Combustor Design Qualification test. October 1998 Energy and Environmental Research Corporation’s CCT III project, Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler, final reports issued and project completed. September 1999 Energy and Environmental Research Corp.’s CCT-I project, Enhancing the Use of Coals by Gas Reburning and Sorbent Injection, final report issued and project completed. New York State Electric and Gas Corp.’s CCT-IV project, Milliken Station Clean Coal Technology Project, final report issued and project completed. New York State Electric and Gas Corp.’s CCT-IV project, Micronized Coal Reburning Demonstration for NO, Control, final report issued and project com- pleted. DOE signed a revised cooperative agreement for Southern Company Services, Inc.’s CCT-II project, Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler, extending the project. Appendix C: Environmental Aspects Introduction The U.S. Department of Energy employs a three- step process to ensure that the CCT Program and its projects comply with the procedural requirements of the National Environmental Policy Act (NEPA), and the regulations for NEPA compliance promulgated by the Council on Environmental Quality (CEQ) (40 CFR Parts 1500-1508) and by DOE (10 CFR Part 1021). This process includes (1) preparation of a programmatic environmental impact statement (PEIS) in 1989; (2) preparation of preselection, project-specific environmental reviews; and (3) prepa- ration of postselection, site-specific NEPA documen- tation. Several types of NEPA documents have been used in the CCT Program, including memoranda-to- file (MTF; discontinued as of September 30, 1990), environmental assessments (EA), and environmental impact statements (EIS). The Department of Ener- gy’s NEPA regulations also provide for categorical exclusions (CX) for certain classes of actions. Exhibit C-1 shows the progress made through September 30, 1999, to complete NEPA reviews of projects in the CCT Program. By September 30, 1999, NEPA reviews were completed for 35 of the 40 CCT projects remaining in the program (two NEPA reviews were completed for one project, Enhancing the Use of Coals by Gas Reburning and Sorbent Injection—an MTF was completed for the Hennepin site and an EA for the Lakeside site). From 1987 through September 30, 1999, NEPA requirements were satisfied with a CX for | project, MTFs for 17 projects, EAs for 18 projects and EISs for 4 projects (actions exceed 33 because of project terminations, withdrawals, and restructuring). For each project cofunded by DOE under the CCT Program, the industrial participant is required to develop an environmental monitoring plan (EMP) that will ensure operational compliance and that significant technical and environmental data are collected and disseminated. Data to be collected include compliance data to meet federal, state, and local requirements and performance data to aid in future commercialization of the technology. Exhibit C-1 NEPA Reviews Completed through September 30, 1999 14 12 10 Number of Projects 0 T i T T FS * Includes an MTF (1988) and an EA (1989) required for one project ali el Memoranda-to-file Environmental assessments b Includes an EA fora project that was withdrawn a a,c c c 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 © Includes an EA for a project that was terminated Se Categorical exclusions i Environmental impact statements Program Update 1999 C-1 The Role of NEPA in the CCT Program NEPA was initially enacted in 1969 as Public Law 91-190 and is codified at 42 U.S.C. §4321 et seq. The applicability of NEPA to the CCT Program is encapsu- lated in the following provision (Section 102): [A]ll agencies of the Federal Government shall—. . . (C) include in every recommendation or report on propos- als for legislation and other major Federal actions signifi- cantly affecting the quality of the human environment, a detailed statement by the responsible official on— i. the environmental impact of the proposed action, ii. any adverse environmental effects which cannot be avoided should the proposal be implemented, iii. alternatives to the proposed action, iv. the relationship between local short-term uses of man’s environment and the maintenance and enhancement of long-term productivity, and v. any irreversible and irretrievable commitments of resources which would be involved in the proposed action should it be implemented. . . . (E) study, develop, and describe appropriate alternatives to recommended courses of action in any proposal which involves unresolved conflicts concerning alternative uses of available resources[.] Through NEPA, Congress created the CEQ, which has promulgated regulations that ensure compliance with the act. Compliance with NEPA In November 1989, a PEIS was completed for the CCT Program. This PEIS addressed issues such as C-2 Program Update 1999 potential global climatic modification and the ecologi- cal and socioeconomic impacts of the CCT Program. The PEIS evaluated the following two alternatives: * “No action,” which assumed that conventional coal-fired technologies with conventional flue gas desulfurization controls would continue to be used, and * “Proposed action,” which assumed that successfully demonstrated clean coal tech- nologies would undergo widespread commer- cialization by the year 2010. In preselection project-specific environmental reviews, DOE evaluates the environmental aspects of each proposed demonstration project. Reviews are provided to the Source Selection Official for consid- eration in the project selection process. The site- specific environmental, health, safety, and socioeco- nomic issues associated with each proposed project are examined during the NEPA review. As part of the comprehensive evaluation prior to selecting projects, the strengths and weaknesses of each pro- posal are compared with the environmental evalua- tion criteria. To the maximum extent possible, the environmental impacts of each proposed project and practical mitigating measures are considered. Also, a list of necessary permits is prepared, to the extent known; these are permits that would need to be obtained in implementing the proposed project. Upon selection, project participants are required to prepare and submit additional environmental informa- tion. This detailed site- and project-specific information is used, along with independent information gathered by DOE, as the basis for site-specific NEPA documents that are prepared by DOE for each selected project. These NEPA documents are prepared, considered, and published in full conformance with CEQ and DOE regulations for NEPA compliance. Categorical Exclusions “Subpart D—Typical Classes of Actions” of the DOE NEPA regulations provides for categorical exclusions as a class of actions that DOE has deter- mined do not individually or cumulatively have a significant effect on the human environment. Two projects, Micronized Coal Reburning Demonstration for NO, Control and Pulse Combustor Design Quali- fication Test, were covered by a categorical exclu- sion. Memoranda-to-File The MTF was established when DOE’s NEPA guidelines were first issued in 1980. The MTF was intended for circumstances when the expected im- pacts of the proposed action were clearly insignifi- cant, yet the action had not been specified as a cate- gorical exclusion from NEPA documentation. The use of the MTF was terminated as of September 30, 1990. Exhibit C-2 lists the 17 projects for which an MTF was prepared. Environmental Assessments An EA has the following three functions: 1. To provide sufficient evidence and analysis for determining whether a proposed action requires preparation of an EIS or a finding of no significant impact (FONSI); 2. To aid an agency’s compliance with NEPA when no EIS is necessary, i.e., to provide an interdisciplinary review of proposed actions, assess potential impacts, and identify better alternatives and mitigation measures; and Exhibit C-2 Memoranda-to-File Completed Project and Participant Completed CCT-I Development of the Coal Quality Expert™ (ABB Combustion Engineering, Inc. and CQ Inc.) LIMB Demonstration Project Extension and Coolside Demonstration (McDermott Technology, Inc.) Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (Coal Tech Corporation) Nucla CFB Demonstration Project (Colorado-Ute Electric Association, Inc.; now Tri-State Generation and Transmission Association, Inc.) Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Hennepin site) (Energy and Environmental Research Corporation) Tidd PFBC Demonstration Project (The Ohio Power Company) 4/27/90 6/2/87 3/26/87 4/18/88 5/9/88 3/5/87 CCT-I SNOX™ Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) SO,-NO,-Rox Box™ Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers (Southern Company Services, Inc.) 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers (Southern Company Services, Inc.) 1/31/90 9/22/89 5/22/89 8/16/89 7/21/89 CCT-Ill 10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) Full-Scale Demonstration of Low-NO, Cell Burner Retrofit (The Babcock & Wilcox Company) Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler (Energy and Environmental Research Corporation) LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC-—North America) Integrated Dry NO./SO, Emissions Control System (Public Service Company of Colorado) 9/21/90 8/10/90 9/25/90 9/6/90 10/2/90 9/27/90 3. To facilitate preparation of an EIS when one is necessary. An EA’s contents are determined on a case-by- case basis and depend on the nature of the action. If appropriate, a DOE EA also includes any floodplain or wetlands assessment that has been prepared, and may include analyses needed for other environmental determinations. If an agency determines on the basis of an EA that it is not necessary to prepare an EIS, a FONSI is issued. Council on Environmental Quality regula- tions describe the FONSI as a document that briefly presents the reasons why an action will not have a significant effect on the human environment and for which an EIS therefore will not be prepared. The FONSI includes the EA, or a summary of it, and notes any other related environmental documents. The CEQ and DOE regulations also provide for notification of the public that a FONSI has been issued. Also, DOE provides copies of the EA and FONSI to the public on request. Exhibit C-3 lists the 18 projects for which an EA has been prepared. The exhibit includes EAs for one project that was subsequently withdrawn from the program—TransAlta Resources Investment Corpora- tion’s Low-NO//SO, Burner Retrofit for Utility Cyclone Boilers project—and three that were termi- nated—ABB Combustion Engineering’s Combustion Engineering IGCC Repowering Project, Bethlehem Steel Corporation’s Innovative Coke Oven Gas Cleaning System for Retrofit Applications, and Pennsylvania Electric’s Warren Station Externally- Fired Combined-Cycle Demonstration Project. Program Update 1999 — C-3 Exhibit C-3 Environmental Assessments Completed Project and Participant Completed CCT-I Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Lakeside site) (Energy and Environmental Research Corporation) 6/25/89 Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) 3/27/91 CCT-II Combustion Engineering IGCC Repowering Project (ABB Combustion Engineering, Inc.) (project terminated) 3/27/92 Demonstration of Coal Reburning for Cyclone Boiler NO, Control (The Babcock & Wilcox Company) 2/12/91 Innovative Coke Oven Gas Cleaning System for Retrofit Applications (Bethlehem Steel Corporation) (project terminated) 12/22/89 Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) 2/16/90 Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) 4/16/90 Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) 8/10/90 Low-NO,/SO, Burner Retrofit for Utility Cyclone Boilers (TransAlta Resources Investment Corporation) (project withdrawn) 3/21/91 CCT-III Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process (Air Products Liquid Phase Conversion Company, L.P.) 6/30/95 Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) 6/8/93 ENCOAL®* Mild Coal Gasification Project (ENCOAL Corporation) 8/1/90 Commercial Demonstration of the NOXSO SO,/NO, Removal Flue Gas Cleanup System (NOXSO Corporation) 6/26/95 CCT-IV Self-Scrubbing Coal™: An Integrated Approach to Clean Air (Custom Coals International) 2/14/94 Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) 8/18/93 Warren Station Externally-Fired Combined-Cycle Demonstration Project (Pennsylvania Electric Company) (Warren Station site) (project terminated) 5/18/95 Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) 5/28/93 CCT-V Clean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) 6/2/97 C-4 Program Update 1999 Environmental Impact Statements The primary purpose of an EIS is to serve as an action-forcing device to ensure that the policies and goals defined in NEPA are infused into the programs and actions of the federal government. An EIS con- tains a full and fair discussion of all significant envi- ronmental impacts. The EIS should inform decision makers and the public of reasonable alternatives that would avoid or minimize adverse impacts or enhance the quality of the human environment. The CEQ regulations state that an EIS is to be more than a disclosure document; it is to be used by federal officials in conjunction with other relevant material to plan actions and make decisions. Analy- sis of alternatives is to encompass those alternatives to be considered by the ultimate decision maker, including a complete description of the proposed action. In short, the EIS is a means of assessing the environmental impacts of a proposed DOE action (rather than justifying decisions already made), prior to making a decision to proceed with the proposed action. Consequently, before a record of decision (ROD) is issued, DOE may not take any action that would have an adverse environmental effect or limit the choice of reasonable alternatives. As seen in Exhibit C-4, the EISs for three projects were complet- ed in 1994. In 1995, DOE issued a ROD on the EIS prepared for the York County Energy Partners project located in York County, Pennsylvania. However, because this project has been restructured, a new NEPA compliance document will be required for the JEA project site. NEPA Actions in Progress Exhibit C-5 lists the status of projects for which the NEPA process has not yet been completed. Exhibit C-4 Environmental Impact Statements Completed Project and Participant Completed* CCT-I York County Energy Partners Cogeneration Project (York County, PA site) 8/11/95 (York County Energy Partners, L.P.) (project relocated) CCT-III Healy Clean Coal Project (Alaska Industrial Development and Export Authority) 3/10/94 Tampa Electric Integrated Gasification Combined-Cycle Project 8/17/94 (Tampa Electric Company) CCT-IV Pifion Pine IGCC Power Project (Sierra Pacific Power Company) 11/8/94 * Completion is the date DOE issued a record of decision. Exhibit C-5 NEPA Reviews in Progress Project and Participant Status CCT-I JEA Large-Scale CFB Combustion Demonstration Project EIS planned (4/00) CCT-II McIntosh Unit 4A PCFB Demonstration Project (Lakeland, City of, Lakeland Electric) EIS planned (10/00) CCT-V McIntosh Unit 4B Topped PCFB Demonstration Project (Lakeland, City of, Lakeland Electric) Clean Power from Integrated Coal/Ore Reduction (CPICOR™) (CPICOR™ Management Company L.L.C.) EIS planned (10/00) EIS planned (12/00) Kentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, L.L.C.) To be determined Program Update 1999 C-5 Environmental Monitoring CCT project participants are required to develop and implement an EMP that addresses both compli- ance and supplemental monitoring. Exhibit C-6 lists the status of EMPs for all 40 projects in the CCT Program. The EMP is intended to ensure collection and dissemination of the significant technology-, project-, and site-specific environmental data neces- sary for evaluation of impacts upon health, safety, and the environment. Further, the data are used to char- acterize and quantify the environmental performance of the technology in order to evaluate its commercial- ization and deployment potential. In addition to regulatory compliance data, further monitoring is required to fulfill the following: + Ensure that emissions, ambient levels of pollutants, and environmental impacts do not exceed expectations projected in the NEPA documents, * Identify any need for corrective action, + Verify the implementation of any mitigative measure that may have been identified in a mitigation action plan pursuant to the provi- sions of an EA or EIS, and + Provide the essential data on the environmen- tal performance of the technology needed to evaluate the potential impact of future com- mercialization, including the ability of the technology to meet requirements of the Clean Air Act and the 1990 amendments. The objective of the CCT Program’s environmental monitoring efforts is to ensure that, when commercially C-6 Program Update 1999 available, clean coal technologies will be capable of responding fully to air toxics regulations that emerge from the CAAA, and to the maximum extent possible, are in the vanguard of cost-effective solutions to concerns about public health and safety related to coal use. Air Toxics Title III of the CAAA lists known hazardous air pollutants (HAPs) and, among other things, calls for the EPA to establish categories of sources that emit these pollutants. Exploratory analyses suggest that HAPs may be released by conventional coal-fired power plants and, presumably, by plants using clean coal technologies. It is expected that emissions standards will be proposed for the electric-power- production-source categories. However, there are many uncertainties as to which HAPs will be regulat- ed, their prevalence in various types and sources of coal, and their nature and fate as functions of combus- tion characteristics and the particular clean coal technology used. The CCT Program recognizes the importance of monitoring HAPs in achieving widespread commer- cialization in the late 1990s and beyond. For all projects with existing cooperative agreements, DOE sought to include HAPs monitoring. A total of 20 projects contain provisions for monitoring HAPs. The CCT-V Program Opportunity Notice (PON) acknowledged the importance of HAPs throughout the solicitation, including them as an aspect of proposal evaluation. The PON addressed the control of air toxics as an environmental performance criterion. Also, in the instructions on proposal preparation, the PON directed proposers as follows: With respect to emission of air toxics, Proposers should consider . . . the particular elements and compounds [listed in Table 5-1 of the PON, “Specific Air Toxics to be Monitored”]. Proposers should present any information known concerning the reduction of emissions of these toxics by [the proposed} technology. Some of the toxics for which the proposed technology may offer control are likely unregulated in the target market at present. The significance and importance of the additional control afforded by the proposed technology for the continued use of coal should be explained. An example of this kind would be one or more particular air toxic compounds controlled by a technology meant for use in power generation. The CCT-V PON also stipulates that information on air toxics be presented in the environmental infor- mation required by DOE. Exhibit C-7 lists the 20 projects that provide for HAPs monitoring. Eleven of these projects have completed the HAPs monitoring requirements. The objective of the HAPs monitoring program is to improve the quality of HAPs data being gathered and to monitor a broader range of plant configurations and emissions control equipment. The CCT Program is coordinating with organiza- tions such as the Electric Power Research Institute (EPRI) and the Ohio Coal Development Office in activities focused on HAPs monitoring and analysis. Further, under the DOE Coal R&D Program, two reports summarizing the source, distribution, and fate of HAPs from coal-fired power plants were published in 1996. A report released in July 1996, Summary of Air Toxics Emissions Testing at Sixteen Utility Plants, provided assessment of HAPs measured in the coal, across the major pollution control devices, and the HAPs emitted from the stack. A second report, A Comprehensive Assessment of Toxics Emissions from Coal-Fired Power Plants: Phase I Results from the Exhibit C-6 Status of Environmental Monitoring Plans for CCT Projects Project and Participant Status CCT-I Development of the Coal Quality Expert™ (ABB Combustion Engineering, Inc. and CQ Inc.) LIMB Demonstration Project Extension and Coolside Demonstration (McDermott Technology, Inc.) Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control (Coal Tech Corporation) Nucla CFB Demonstration Project (Colorado-Ute Electric Association, Inc.; now Tri-State Generation and Transmission Association, Inc.) Enhancing the Use of Coals by Gas Reburning and Sorbent Injection (Energy and Environmental Research Corporation) Tidd PFBC Demonstration Project (The Ohio Power Company) Advanced Coal Conversion Process Demonstration (Western SynCoal LLC) JEA Large-Scale CFB Combustion Demonstration Project (JEA) Completed 7/31/90 Completed 10/19/88 Completed 9/22/87 Completed 2/27/88 Completed 10/15/89 (Hennepin) Completed 11/15/89 (Lakeside) Completed 5/25/88 Completed 4/7/92 Projected 6/01 CCT-I SNOX™ Flue Gas Cleaning Demonstration Project (ABB Environmental Systems) Demonstration of Coal Reburning for Cyclone Boiler NO, Control (The Babcock & Wilcox Company) SO,-NO,-Rox Box™ Flue Gas Cleanup Demonstration Project (The Babcock & Wilcox Company) Cement Kiln Flue Gas Recovery Scrubber (Passamaquoddy Tribe) Advanced Flue Gas Desulfurization Demonstration Project (Pure Air on the Lake, L.P.) Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler (Southern Company Services, Inc.) Demonstration of Innovative Applications of Technology for the CT-121 FGD Process (Southern Company Services, Inc.) Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High-Sulfur-Coal-Fired Boilers (Southern Company Services, Inc.) 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers (Southern Company Services, Inc.) Completed 10/31/91 Completed 11/18/91 Completed 12/31/91 Completed 3/26/90 Completed 1/31/91 Completed 9/14/90 Completed 12/18/90 Completed 3/11/93 Completed 12/27/90 Program Update 1999 | C-7 Exhibit C-6 (continued) Status of Environmental Monitoring Plans for CCT Projects Project and Participant Status CCT-IIl 10-MWe Demonstration of Gas Suspension Absorption (AirPol, Inc.) Healy Clean Coal Project (Alaska Industrial Development and Export Authority) Full-Scale Demonstration of Low-NO, Cell Burner Retrofit (The Babcock & Wilcox Company) Confined Zone Dispersion Flue Gas Desulfurization Demonstration (Bechtel Corporation) Blast Furnace Granular-Coal Injection System Demonstration Project (Bethlehem Steel Corporation) McIntosh Unit 4A PCFB Demonstration Project (Lakeland, City of, Lakeland Electric) ENCOAL® Mild Coal Gasification Project (ENCOAL Corporation) Evaluation of Gas Reburning and Low-NO, Burners on a Wall-Fired Boiler (Energy and Environmental Research Corporation) LIFAC Sorbent Injection Desulfurization Demonstration Project (LIFAC-North America) Integrated Dry NO /SO, Emissions Control System (Public Service Company of Colorado) Tampa Electric Integrated Gasification Combined-Cycle Projeét (Tampa Electric Company) Commercial Demonstration of the NOXSO SO,/ NO, Removal Flue Gas Cleanup System (NOXSO Corporation) Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process (Air Products Liquid Phase Conversion Company, L.P.) Completed 8/29/96 Completed 10/2/92 Completed 4/11/97 Completed 8/9/91 Completed 6/12/91 Completed 12/23/94 Projected 8/01 Completed 5/29/92 Completed 7/26/90 Completed 6/12/92 Completed 8/5/93 Completed 5/96 To be determined CCT-IV Micronized Coal Reburning Demonstration for NO, Control (New York State Electric & Gas Corporation) Milliken Clean Coal Technology Demonstration Project (New York State Electric & Gas Corporation) Pifion Pine IGCC Power Project (Sierra Pacific Power Company) Wabash River Coal Gasification Repowering Project (Wabash River Coal Gasification Repowering Project Joint Venture) Pulse Combustor Design Qualification Test (ThermoChem, Inc.) Self-Scrubbing Coal™: An Integrated Approach to Clean Air (Custom Coals International) Completed 8/97 Completed 12/1/94 Projected 12/31/00 Completed 7/9/93 To be determined To be determined CCT-V Clean Coal Diesel Demonstration Project (Arthur D. Little, Inc.) Clean Power from Integrated Coal/Ore Reduction (CPICOR™) (CPICOR™ Management Company L.L.C.) Kentucky Pioneer Energy IGCC Demonstration Project (Kentucky Pioneer Energy, L.L.C.) McIntosh Unit 4B Topped PCFB Demonstration Project (Lakeland, City of, Lakeland Electric) Projected 2/99 Projected 9/02 To be determined Projected 8/03 C-8 Program Update 1999 Exhibit C-7 CCT Projects Monitoring Hazardous Air Pollutants Application Category Participant Project Status Advanced Electric Arthur D. Little, Inc. Clean Coal Diesel Demonstration Project Planned Power Generation Kentucky Pioneer Energy, L.L.C. Kentucky Pioneer Energy IGCC Demonstration Project Planned Lakeland, City of, Lakeland Electric MelIntosh Unit 4B Topped PCFB Demonstration Project Planned The Ohio Power Company Tidd PFBC Demonstration Project Completed Sierra Pacific Power Company Pifion Pine IGCC Power Project Planned Tampa Electric Company Wabash River Coal Gasification Repowering Project Joint Venture Tampa Electric Integrated Gasification Combined-Cycle Project Wabash River Coal Gasification Repowering Project In progress In progress JEA JEA Large-Scale CFB Combustion Demonstration Project Planned Environmental ABB Environmental Systems SNOX™ Flue Gas Cleaning Demonstration Project Completed Control Devices AirPol, Inc. 10-MWe Demonstration of Gas Suspension Absorption Completed The Babcock & Wilcox Company Demonstration of Coal Reburning for Cyclone Boiler NO, Control Completed The Babcock & Wilcox Company SO,-NO,-Rox Box™ Flue Gas Cleanup Demonstration Project Completed New York State Electric & Gas Corporation Milliken Clean Coal Technology Demonstration Project Completed Public Service Company of Colorado Integrated Dry NO./SO, Emissions Control System Completed Pure Air on the Lake, L.P. Advanced Flue Gas Desulfurization Demonstration Project Completed Southern Company Services, Inc. Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Completed Southern Company Services, Inc. Demonstration of Innovative Applications of Technology for the Completed CT-121 FGD Process Southern Company Services, Inc. 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Completed Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers Coal Processing for = ENCOAL Corporation ENCOAL®* Mild Coal Gasification Project Completed Clean Fuels Industrial CPICOR™ Management Company L.L.C. Clean Power from Integrated Coal/Ore Reduction (CPICOR™) Planned Applications Program Update 1999 Cc-9 U.S. Department of Energy Study, was released in September 1996 and provided the raw data from the emissions testing. Emissions data were collected from 16 power plants, representing nine process configurations, operated by eight different utilities; several power plants were sites for CCT Program projects. The power plants represented a range of different coal types, process configurations, furnace types, and pollution control methods. The second phase of the DOE/EPRI effort cur- rently in progress is sampling at other sites, including the CCT Program’s Wabash River IGCC project. Further, the results from the first phase will be used to determine what configuration and coal types require further assessment. In October 1996, EPA submitted to Congress an interim version of its technical assessment of toxic air pollutant emissions from power plants, Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Units, Interim Final Report. EPA plans to continue evaluating the potential expo- sures and potential public health concerns from mercury emissions from utilities. In addition, the agency will evaluate information on various potential control technologies for mercury. If EPA decides that HAPs pose a risk, then the agency must propose air toxic emissions controls by November 15, 1998, and make them final two years later. Following up on the October 1996 report to Congress, a report was released by EPA focusing on Mercury emissions. The December 1997 report, Mercury Study Report to Congress, estimates the U.S. industrial sources were responsible for releasing 158 tons of Mercury into the atmosphere in 1994 and 1995. The EPA estimates that 87 percent of those emissions originate from combustion sources such as waste and C-10 Program Update 1999 fossil fuel facilities, 10 percent from manufacturing facilities, 2 percent from area sources, and | percent from other sources. The EPA also identified four specific categories that account for about 80 percent of the total anthropogenic sources: coal-fired power plants, 33 percent; municipal waste incinerators, 18 percent; commercial and industrial boilers, 18 per- cent; and medical waste incinerators, 10 percent. The next step for EPA is to assess the need for enhanced research on health effects and on new pollution control technologies, community “right-to- know” approaches, and regulatory actions. The results of the HAPs program have signifi- cantly mitigated concerns about HAPs emission from coal-fired generation and focused attention on but a few flue gas constituents. The results have the potential to make the forthcoming EPA regula- tions less strict, which could avoid unnecessary control costs and thus save consumers money on electricity bills. Appendix D: CCT Project Contacts Project Contacts Listed below are contacts for obtaining further information about specific CCT Program demonstration projects. Listed are the name, title, phone number, fax number, mailing address, and e-mail address, if available, for the project participants’ contact person. In those instances where the project participant consists of more than one company, a partnership, or joint venture, the mailing address listed is that of the contact person. In addition, the names, phone numbers, and e-mail addresses for contact persons at DOE Headquarters and the National Energy Technology Laboratory (NETL) are provided. Environmental Control Devices SO, Control Technologies 10-MWe Demonstration of Gas Suspension Absorption Participant: AirPol, Inc. Contacts: Niels H. Kastrup (281) 539-3400 (281) 539-3411 (fax) nhk@flsmiljous.com FLS miljo, Inc. 100 Glenborough Drive Houston, TX 77067 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov Confined Zone Dispersion Flue Gas Desulfurization Demonstration Participant: Bechtel Corporation Contacts: Joseph T. Newman, Project Manager (415) 768-1189 (415) 768-5420 (fax) Bechtel Corporation P.O. Box 193965 San Francisco, CA 94119-3965 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov LIFAC Sorbent Injection Desulfurization Demonstration Project Participant: LIFAC-North America Contacts: Dan Stap, Project Manager (412) 497-2231 (412) 497-2212 (fax) ICF Kaiser Engineers, Inc. Gateway View Plaza 1600 West Carson Street Pittsburgh, PA 15219-1031 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov Program Update 1999 — D-1 Advanced Flue Gas Desulfurization Demonstration Project Participant: Pure Air on the Lake, L.P. Contacts: Tim Roth (610) 481-6257 (610) 481-2762 (fax) Pure Air on the Lake, L.P. c/o Air Products and Chemicals, Inc. 7201 Hamilton Boulevard Allentown, PA 18195-1501 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov Demonstration of Innovative Applications of Technology for the CT-121 FGD Process Participant: Southern Company Services, Inc. Contacts: David P. Burford, Project Manager (205) 992-6329 (205) 992-7535 (fax) dpburfor@southernco.com Southern Company Services, Inc. P.O. Box 2625 Birmingham, AL 35202-2625 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov D-2 Program Update 1999 NO, Control Technologies Micronized Coal Reburning Demonstration for NO, Control Participant: New York State Electric & Gas Corporation Contacts: Jim Harvilla (607) 762-8630 (607) 762-8457 (fax) New York State Electric & Gas Corporation Corporate Drive - Kirkwood Industrial Park P.O. Box 5224 Binghamton, NY 13902-5224 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov Demonstration of Coal Reburning for Cyclone Boiler NO, Control Participant: The Babcock & Wilcox Company Contacts: Dot K. Johnson (330) 829-7395 (330) 829-7801 (fax) dot.k.johnson@medermott.com McDermott Technologies 1562 Beeson Street Alliance, OH 44601 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov John C. McDowell, NETL, (412) 386-6175 mcedowell@netl.doe.gov Full-Scale Demonstration of Low-NO, Cell Burner Retrofit Participant: The Babcock & Wilcox Company Contacts: Dot K. Johnson (330) 829-7395 (330) 829-7801 (fax) dot.k.johnson@mcdermott.com McDermott Technologies 1562 Beeson Street Alliance, OH 44601 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov Evaluation of Gas Reburning and Low-NO_ Burners on a Wall-Fired Boiler Participant: Energy and Environmental Research Corporation Contacts: Blair A. Folsom, Senior Vice President (949) 859-8851, ext. 140 (949) 859-3194 (fax) General Electric Energy and Environmental Research Corporation 18 Mason Irvine, CA 92618 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov Jerry L. Hebb, NETL, (412) 386-6079 hebb@netl.doe.gov Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers Participant: Southern Company Services, Inc. Contacts: Larry Monroe (205) 257-7772 (205) 257-5367 (fax) Southern Company Services, Inc. P.O. Box 2641 Birmingham, AL 35291-8195 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov 180-MWe Demonstration of Advanced Tangentially-Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers Participant: Southern Company Services, Inc. Contacts: Larry Monroe (205) 257-7772 (205) 257-5367 (fax) Southern Company Services, Inc. P.O. Box 2641 Birmingham, AL 35291-8195 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler Participant: Southern Company Services, Inc. Contacts: John N. Sorge, Research Engineer (205) 257-7426 (205) 257-5367 (fax) Southern Company Services, Inc. P.O. Box 2641 Birmingham, AL 35291-8195 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James R. Longanbach, NETL, (304) 285-4659 jlonga@netl.doe.gov Combined SO,/NO, Control Technologies Milliken Clean Coal Technology Demonstration Project Participant: New York State Electric & Gas Corporation Contacts: Jim Harvilla (607) 762-8630 (607) 762-8457 (fax) New York State Electric & Gas Corporation Corporate Drive-Kirkwood Industrial Park P.O. Box 5224 Binghamton, NY 13902-5224 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov SNOX™ Flue Gas Cleaning Demonstration Project Participant: ABB Environmental Systems Contacts: Paul Yosick, Project Manager (423) 693-7550 (423) 694-5203 (fax) ABB Environmental Systems 1409 Center Point Boulevard Knoxville, TN 37932 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov LIMB Demonstration Project Extension and Coolside Demonstration Participant: The McDermott Technology, Inc. Contacts: Paul Nolan (330) 860-1074 (330) 860-2045 (fax) The McDermott Technology, Inc. 20 South Van Buren Avenue P.O. Box 351 Barberton, OH 44203-0351 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov John C. McDowell, NETL, (412) 386-6175 medowell@netl.doe.gov Program Update 1999 D-3 SO,-NO -Rox Box™ Flue Gas Cleanup Demonstration Project Participant: The Babcock & Wilcox Company Contacts: Dot K. Johnson (330) 829-7395 (330) 829-7801 (fax) dot.k.johnson@mcdermott.com McDermott Technologies 1562 Beeson Street Alliance, OH 44601 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov Enhancing the Use of Coals by Gas Reburning and Sorbent Injection Participant: Energy and Environmental Research Corporation Contacts: Blair A. Folsom, Senior Vice President (949) 859-8851, ext. 140 (949) 859-3 194 (fax) General Electric Energy and Environmental Research Corporation 18 Mason Irvine, CA 92618 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov Jerry L. Hebb, NETL, (412) 386-6079 hebb@netl.doe.gov D-4 Program Update 1999 Integrated Dry NO/SO, Emissions Control System Participant: Public Service Company of Colorado Contacts: Terry Hunt, Project Manager (303) 571-7113 (303) 571-7868 (fax) thunt@ueplaza.com Utility Engineering 550 15" Street, Suite 800 Denver, CO 80202-4256 Lawrence Saroff, DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov Jerry L. Hebb, NETL, (412) 386-6079 hebb@netl.doe.gov Commercial Demonstration of the NOXSO SO,/ NO, Removal Flue Gas Cleanup System Participant: NOXSO Corporation Contacts: Lawrence Saroff DOE/HQ, (301) 903-9483 lawrence.saroff@hq.doe.gov Jerry L. Hebb, NETL, (412) 386-6079 hebb@netl.doe.gov Advanced Electric Power Generation Fluidized-Bed Combustion McIntosh Unit 4A PCFB Demonstration Project Participant: City of Lakeland, Lakeland Electric Contacts: Alfred M. Dodd, Project Manager (941) 499-6461 (941) 499-6344 (fax) Lakeland Electric 501 E. Lemon Street Lakeland, FL 33801-5079 George Lynch, DOE/HQ, (301) 903-9434 george.lynch@hq.doe.gov Donald L. Bonk, NETL, (304) 285-4889 dbonk@netl.doe.gov McIntosh Unit 4B Topped PCFB Demonstration Project Participant: City of Lakeland, Lakeland Electric Contacts: Alfred M. Dodd, Project Manager (941) 499-6461 (941) 499-6344 (fax) Lakeland Electric 501 E. Lemon Street Lakeland, FL 33801-5079 George Lynch, DOE/HQ, (301) 903-9434 george.lynch@hq.doe.gov Donald L. Bonk, NETL, (304) 285-4889 dbonk@netl.doe.gov JEA Large-Scale CFB Combustion Demonstration Project Participant: JEA Contacts: Reece E. Comer, Jr. P.E. (904) 665-6312 (904) 665-7263 (fax) comere@jea.com JEA 21 West Church Street, Tower 10 Jacksonville, FL 32202-3139 George Lynch, DOE/HQ, (301) 903-9434 george.lynch@hq.doe.gov Jerry L. Hebb, NETL, (412) 386-6079 hebb@netl.doe.gov Tidd PFBC Demonstration Project Participant: American Electric Power Service Corporation as agent for The Ohio Power Company Contacts: Michael J. Mudd (614) 223-1585 (614) 223-2499 (fax) mjmudd@aep.com American Electric Power Service Corporation 1 Riverside Plaza Columbus, OH 43215 George Lynch, DOE/HQ, (301) 903-9434 george.lynch@hq.doe.gov Donald W. Geiling, NETL, (304) 285-4784 dgeili@netl.doe.gov Nucla CFB Demonstration Project Participant: Tri-State Generation and Transmission Association, Inc. Contacts: Stuart Bush (303) 452-6111 (303)254-6066 (fax) Tri-State Generation and Transmission Association, Inc. P.O. Box 33695 Denver, CO 80233 George Lynch, DOE/HQ, (301) 903-9434 george.lynch@hq.doe.gov Thomas Sarkus, NETL (412) 386-5981 sarkus@netl.doe.gov Integrated Gasification Combined-Cycle Kentucky Pioneer IGCC Demonstration Project Participant: Kentucky Pioneer Energy, L.L.C. Contacts: H. H. Graves, President (513) 621-0077 (513) 621-5947 (fax) hhg@globalenergyinc.com Kentucky Pioneer Energy, L.L.C. 312 Walnut Street, Suite 200 Cincinnati, OH 45202 George Lynch, DOE/HQ, (301) 903-9434 george.lynch@hq.doe.gov Douglas M. Jewell, NETL, (304) 285-4720 doug.jewell@netl.doe.gov Pifion Pine IGCC Power Project Participant: Sierra Pacific Power Company Contacts: Jeffrey W. Hill, Director Power Generation (775) 834-5650 (775) 834-5704 (fax) jhill@sppe.com Sierra Pacific Power Company P.O. Box 10100 Reno, NV 89520-0024 George Lynch, DOE/HQ, (301) 903-9434 george.lynch@hq.doe.gov Donald W. Geiling, NETL, (304) 285-4784 dgeili@netl.doe.gov Web Site: http://www.sierrapacific.com/utilserv/electric/pinon/ Program Update 1999 D-5 Tampa Electric Integrated Gasification Combined- Cycle Project Participant: Tampa Electric Company Contacts: Donald E. Pless, Director, Advanced Technology (813) 228-1111, ext. 46201 (813)641-5300 (fax) TECO Energy P.O. Box 111 Tampa, FL 33601-0111 George Lynch, DOE/HQ, (301) 903-9434 george.lynch@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov Web Site: http://www.teco.net/teco/TEK PlkPwrStn.html Wabash River Coal Gasification Repowering Project Participant: Wabash River Coal Gasification Repowering Project Joint Venture Contacts: Phil Amick, Director of Gasification Development (713) 767-8667 (713) 767-8515 (fax) pram@dynegy.com Dynegy 1000 Louisiana St., Suite 5800 Houston, TX 77002 George Lynch, DOE/HQ, (301) 903-9434 george.lynch@hq.doe.gov Leo E. Makovsky, NETL, (412) 386-5814 makovsky@netl.doe.gov D-6 Program Update 1999 Advanced Combustion/Heat Engines Healy Clean Coal Project Participant: Alaska Industrial Development and Export Authority Contacts: Dennis V. McCrohan, Deputy Director, Project Development and Operations (907) 269-3025 (907) 269-3044 (fax) dmecrohan@aidea.org Alaska Industrial Development and Export Authority 480 West Tudor Road Anchorage, AK 99503-6690 George Lynch, DOE/HQ, (301) 903-9434 george.lynch@hq.doe.gov Robert M. Kornosky, NETL, (412) 386-4521 robert.kornosky@netl.doe.gov Clean Coal Diesel Demonstration Project Participant: Arthur D. Little, Inc. Contacts: Robert P. Wilson, Vice President (617) 498-5806 (617)498-7206 (fax) Arthur D. Little, Inc. Building 15, Room 259 25 Acorn Park Cambridge, MA 02140 George Lynch, DOE/HQ, (301) 903-9434 george.lynch@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov Coal Processing for Clean Fuels Indirect Liquefaction Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) Process Participant: Air Products Liquid Phase Conversion Company, L.P. Contacts: Edward C. Heydorn, Project Manager (610) 481-7099 (610) 706-7299 (fax) heydorec@apci.com Air Products and Chemicals, Inc. 7201 Hamilton Boulevard Allentown, PA 18195-1501 Edward Schmetz, DOE/HQ, (301) 903-3931 edward.schmetz@hq.doe.gov Robert M. Kornosky, NETL, (412) 386-4521 robert.kornosky@netl.doe.gov Coal Preparation Technologies Advanced Coal Conversion Process Demonstration Participant: Western SynCoal LLC Contacts: Ray W. Sheldon, P.E., Director of Development (406) 252-2277, ext. 456 (406) 252-2090 (fax) Western SynCoal Partnership P.O. Box 7137 Billings, MT 59103-7137 Douglas Archer, DOE/HQ, (301) 903-9443 douglas.archer@hq.doe.gov Joseph B. Renk II, NETL, (412) 386-6406 joseph.renk@netl.doe.gov Development of the Coal Quality Expert™ Participants: ABB Combustion Engineering, Inc. and CQ Inc. Contacts: Clark D. Harrison, President (724) 479-3503 (724)479-418 | (fax) CQ Inc. 160 Quality Center Rd. Homer City, PA 15748 Douglas Archer, DOE/HQ, (301) 903-9443 douglas.archer@hq.doe.gov Joseph B. Renk III, NETL, (412) 386-6406 joseph.renk@netl.doe.gov Web Site: http://www. fuels.bv.com:80/cge/cge.htm Mild Gasification ENCOAL!?® Mild Coal Gasification Project Participant: ENCOAL Corporation Contacts: James P. Frederick, Project Director (307) 686-2720, ext. 27 (307) 686-2894 (fax) jfrederick@ven.com SGI International P.O. Box 3038 Gillette, WY 82717 Douglas Archer, DOE/HQ, (301) 903-9443 douglas.archer@hq.doe.gov Douglas M. Jewell, NETL, (304) 285-4720 doug.jewell@netl.doe.gov Self-Scrubbing Coal™: An Integrated Approach to Clean Air Participant: Custom Coals International Contacts: Douglas Archer, DOE/HQ, (301) 903-9443 douglas.archer@hq.doe.gov Joseph B. Renk III, NETL, (412) 386-6406 joseph.renk@netl.doe.gov Industrial Applications Blast Furnace Granular-Coal Injection System Demonstration Project Participant: Bethlehem Steel Corporation Contacts: Robert W. Bouman, Project Director (610) 694-6792 (610)694-298 | (fax) Bethlehem Steel Corporation Building C, Room 211 Homer Research Laboratory Mountain Top Campus Bethlehem, PA 18016 Douglas Archer, DOE/HQ, (301) 903-9443 douglas.archer@hq.doe.gov Leo E. Makovsky, NETL, (412) 386-5814 makovsky@netl.doe.gov Clean Power from Integrated Coal/Ore Reduction (CPICOR™) Participant: CPICOR™ Management Company, L.L.C. Contacts: Reginal Wintrell, Project Director (801) 227-9214 (801)227-9198 (fax) CPICOR™ Management Company L.L.C. P.O. Box 2500 Provo, UT 84603 William E. Fernald, DOE/HQ, (301) 903-9448 william.fernald@hq.doe.gov Douglas M. Jewell, NETL, (304) 285-4720 doug.jewell@netl.doe.gov Program Update 1999 D-7 Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control Participant: Coal Tech Corporation Contacts: Bert Zauderer, President (610) 667-0442 (610) 667-0576 (fax) coaltechbz@compuserve.com Coal Tech Corporation P.O. Box 154 Merion Station, PA 19066 William E. Fernald, DOE/HQ, (301) 903-9448 william. fernald@hq.doe.gov James U. Watts, NETL, (412) 386-5991 james.watts@netl.doe.gov Cement Kiln Flue Gas Recovery Scrubber Participant: Passamaquoddy Tribe Contacts: Thomas N. Tureen, Project Manager (207) 773-7166 (207) 773-8832 (fax) ttureen@gwi.com Passamaquoddy Technology, L.P. 1 Monument Way Portland, ME 04101 William E. Fernald, DOE/HQ, (301) 903-9448 william.fernald@hq.doe.gov John C. McDowell, NETL, (412) 386-6175 medowell@netl.doe.gov D-8 — Program Update 1999 Pulse Combustor Design Qualification Test Participant: ThermoChem, Inc. Contacts: William G. Steedman, Sr. Systems Engineer (410) 354-9890 (410) 354-9894 (fax) wsteedman@tchem.net ThermoChem, Inc. 6001 Chemical Road Baltimore, MD 21226 William E. Fernald, DOE/HQ, (301) 903-9448 william. fernald@hq.doe.gov Robert M. Kornosky, NETL, (412) 386-4521 robert.kornosky@netl.doe.gov Appendix E: Acronyms, Abbreviations, and Symbols Acronyms, Abbreviations, and Symbols °C degrees Celsius °F degrees Fahrenheit $ dollars (U.S.) $/kw dollars per kilowatt $/ton dollars per ton % percent ® registered trademark ™ trademark ABB CE ABB Combustion Engineering, Inc. ABB ES ABB Environmental Systems ACFB atmospheric circulating fluidized- bed ADL Arthur D. Little, Inc. AEO99 Annual Energy Outlook 1999 AEO2000 Annual Energy Outlook 2000 AERYS Annual Energy Review 1998 AFBC atmospheric fluidized-bed combustion AFGD advanced flue gas desulfurization AIDEA Alaska Industrial Development and Export Authority AOFA advanced overfire air APF advanced particulate filter ARIL Advanced Retractable Injection Lanes ASME Ass’n. ATCF atm avg. BFGCI BG BG/L Btu Btu/kWh B&W CAAA CaCO, CaO Ca(OH), Ca(OH),*MgO Ca/N CAPI Ca/S CaSO, CaSO, CCOFA CCT CCT I CCT Il American Society of Mechanical Engineers Association after tax cash flows atmosphere(s) average blast furnace granular-coal injection British Gas British Gas/Lurgi British thermal unit(s) British thermal units per kilowatt- hour The Babcock & Wilcox Company Clean Air Act Amendments of 1990 calcium carbonate (calcitic limestone) calcium oxide (lime) calcium hydroxide (calcitic hydrated lime) dolomitic hydrated lime calcium/nitrogen Clean Air Power Initiative calcium-to-sulfur calcium sulfite calcium sulfate close-coupled overfire air clean coal technology First CCT Program solicitation Second CCT Program solicitation CCT Ill CCT IV CCT V CCT Program CD-ROM CDL* CEQ CFB C/H CKD co co, CoP CT-121 CQE™ CQIM™ cx cZD DER DME DOE DOE/HQ DSE DSI EA EER Third CCT Program solicitation Fourth CCT Program solicitation Fifth CCT Program solicitation Clean Coal Technology Demonstration Program Compact disk-read only memory Coal-Derived Liquid® Council on Environmental Quality circulating fluidized-bed carbon/hydrogen cement kiln dust carbon monoxide carbon dioxide Conference of Parties Chiyoda Thoroughbred-121 Coal Quality Expert™ Coal Quality Impact Model™ categorical exclusion confined zone dispersion discrete emissions reduction dimethyl ether U.S. Department of Energy U.S. Department of Energy Headquarters dust stabilization enhancement dry sorbent injection environmental assessment Energy and Environmental Research Corporation Program Update 1999 E-1 EERC EFCC EIA EIS EIV EMP EPA EPAct EPDC EPRI ESP EWG ext. FBC FCCC FeO Fe,S 2! FERC FETC FGD FONSI FRP ft, ft, fe FY gal. gal/ft GB GE GHG Energy and Environmental Research Center, University of North Dakota externally fired combined cycle Energy Information Administration environmental impact statement Environmental Information Volume environmental monitoring plan U.S. Environmental Protection Agency Energy Policy Act of 1992 Japan’s Electric Power Development Company Electric Power Research Institute electrostatic precipitator exempt wholesale generator extension fluidized-bed combustion Framework Convention on Climate Change iron oxide pyritic sulfur Federal Energy Regulatory Commission Federal Energy Technology Center (now NETL) flue gas desulfurization finding of no significant impact fiberglass-reinforced plastic foot (feet), square feet, cubic feet fiscal year gallon(s) gallons per cubic feet gigabyte(s) General Electric greenhouse gases E-2__ Program Update 1999 GNOCIS gpm GR GR-LNB GR-SI GSA GVEA GW GWe H,S H,SO, HAP HCl HF HGPFS HHV hr. HRSG ID IEA IEO99 IGCC in, in’, in> JBR KCl K,SO, kW kWh Ib. LIG LHV LIMB Generic NO, Control Intelligence System gallons per minute gas reburning gas reburning and low-NO, burner gas reburning and sorbent injection gas suspension absorption Golden Valley Electric Association gigawatt(s) gigawatt(s)-electric hydrogen sulfide sulfuric acid hazardous air pollutant hydrogen chloride hydrogen fluoride hot gas particulate filter system high heating value hour(s) heat recovery steam generator Induced Draft International Energy Agency International Energy Outlook 1999 integrated gasification combined- cycle inch(es), square inches, cubic inches Jet Bubbling Reactor” potassium chloride potassium sulfate kilowatt(s) kilowatt-hour(s) pound(s) liquid-to-gas ratio low heating value limestone injection multistage burner LNB LNCB*® LNCFS LOI LPMEOH™ LRCWF LSFO MASB MB MCFC MDEA MgCo, MgO Mhz mills/kWh min. mo. MTCI MTF MW MWe Mwt N, Na/Ca Na/S NaOH Na,CO, NAAQS NEPA NETL NH Nm* NO. low-NO, burner low-NO, cell burner Low-NO, Concentric-Firing System loss-on-ignition Liquid phase methanol™ low-rank coal-water-fuel limestone forced oxidation multi-annular swirl burner megabyte(s) molten carbonate fuel cell methyldiethanolamine magnesium carbonate magnesium oxide megahertz mills per kilowatt hour minute(s) month(s) Manufacturing and Technology Conversion International memorandum (memoranda)-to-file megawatt(s) megawatt(s)-electric megawatt(s)-thermal atmospheric nitrogen sodium/calcium sodium/sulfur sodium hydroxide sodium carbonate National Ambient Air Quality Standards National Environmental Policy Act National Energy Technology Laboratory (formerly FETC) ammonia Normal cubic meter nitrogen dioxide NOPR NO, NSPS NSR NTHM NTIS NYSEG OC&PS O&M 0, OTAG oTc PASS PC PCAST PCFB PDF® PEIA PEIS PEOA™ PENELEC PEP PFBC PJBH PM PM 10 Notice of Proposed Rulemaking nitrogen oxides New Source Performance Standards normalized stoichiometric ratio net tons of hot metal National Technical Information Service New York State Electric & Gas Corporation Office of Coal & Power Systems operation and maintenance oxygen Ozone Transport Assessment Group Ozone Transport Commission Pilot Air Stabilization System personal computer Presidential Committee of Advisors on Science and Technology pressurized circulating fluidized bed Process-Derived Fuel” programmatic environmental impact assessment programmatic environmental impact statement Plant Emission Optimization Advisor™ Pennsylvania Electric Company progress evaluation plan pressurized fluidized-bed combustion pulse jet baghouse particulate matter particulate matter less than 10 microns in diameter PM, PON PRB ppm ppmv PSCC PSD psi psia psig PUHCA PURPA QF RAM R&D RD&D REA RP&L ROD ROM rpm RUS SBIR sef scfm SCR SCS particulate matter less than 2.5 microns in diameter program opportunity notice Powder River Basin parts per million (mass) parts per million by volume Public Service Company of Colorado Prevention of Significant Deterioration pound(s) per square inch pound(s) per square inch absolute pound(s) per square inch gauge Public Utility Holding Company Act of 1935 Public Utility Regulatory Policies Act of 1978 qualifying facility random access memory research and development research, development, and demonstration Rural Electrification Administration Richmond Power & Light Record of Decision run-of-mine revolutions per minute Rural Utility Service sulfur Small Business Innovation Research standard cubic feet standard cubic feet per minute selective catalytic reduction Southern Company Services, Inc. SFC S-H-U SI SIP SM SNCR SNRB™ SO. so, std ft SOFA STTR SVGA TAG™ TCLP TVA UAF UARG UBCL U.K. UNESCO US. VFB VOC WC WES WLFO wt. yr. Synthetic Fuels Corporation Saarberg-H6lter-Umwelttechnik sorbent injection state implementation plan service mark selective noncatalytic reduction SO,-NO,-Rox Box™ sulfur dioxide sulfur trioxide standard cubic feet separated overfire air Small Business Technology Transfer Program super video graphics adapter Technical Assessment Guide™ toxicity characteristics leaching procedure Tennessee Valley Authority University of Alaska, Fairbanks Utility Air Regulatory Group unburned carbon losses United Kingdom United Nations Educational, Scientific and Cultural Organization United States vibrating fluidized-bed volatile organic compound water column wastewater evaporation system wet limestone, forced oxidation weight year(s) Program Update 1999 E-3 State Abbreviations AL AK AZ AR CA co CT DE DC FL GA HI ID IL IN IA KS KY LA ME MD MA MI MN MS MO MT NE NV NH NJ NM NY E-4 Alabama Alaska Arizona Arkansas California Colorado Connecticut Delaware District of Columbia Florida Georgia Hawaii Idaho Illinois Indiana lowa Kansas Kentucky Louisiana Maine Maryland Massachusetts Michigan Minnesota Mississippi Missouri Montana Nebraska Nevada New Hampshire New Jersey New Mexico New York Program Update 1999 NC North Carolina ND North Dakota OH Ohio OK Oklahoma OR Oregon PA Pennsylvania PR Puerto Rico RI Rhode Island SC South Carolina SD South Dakota TN Tennessee TX Texas UT Utah VT Vermont VA Virginia VI Virgin Islands WA Washington WV West Virginia WI Wisconsin WY Wyoming Other Some companies have adopted an acronym as their corporate names. The following corporate names reflect the former name of the company. BG/L British Gas Lurgi JEA Jacksonville Electric Authority Index of CCT Projects and Participants # 10-MWe Demonstration of Gas Suspension Absorption ES-7, ES-11, ES-22, 2-7, 3-8, 4-4, 5-3, 5-15, 5-17, 5-20, B-3, B-5, C-3, C-8, C-9, D-1 180-MWe Demonstration of Advanced Tangentially- Fired Combustion Techniques for the Reduction of NO, Emissions from Coal-Fired Boilers ES- 8, ES-12, ES-22, 2-7, 4-5, 5-5, 5-15, 5-18, 5-66, B-3, B-5, C-3, C-7, C-9, D-3 A ABB Combustion Engineering, Inc. ES-17, ES-18, ES-23, ES-24, 2-7, 3-8, 4-3, 4-9, 4-12, 4-13, 5-10, 5-16, 5-17, 5-58, 5-66, 5-90, 5-138, B-2, B-3, B-5, B-6, C-3, C-4, C-7, D-7, E-1 ABB Environmental Systems ES-9, ES-12, ES-22, 2-7, 4-7, 5-15, 5-17, 5-74, B-6, C-3, C-7, C-9, D-3, E-1 ACFB Repowering B-2 Advanced Coal Conversion Process Demonstration ES-18, ES-23, 2-7, 4-12, 5-11, 5-16, 5-18, 5-136, B-2, B-3, C-4, C-7, D-7 Advanced Cyclone Combustor with Internal Sulfur, Nitrogen, and Ash Control ES-19, ES-23, 2-7, 4-12, 5-13, 5-16, 5-17, 5-156, B-1, B-4, C-3, C-7, D-8 Advanced Flue Gas Desulfurization Demonstration Project ES-7, ES-11, ES-22, ES-24, 2-7, 3-8, 4-4, 4-13, 5-3, 5-15, 5-18, 5-32, B-2, B-5, C-4, C-7, C-9, D-2 Advanced Slagging Coal Combustor Utility Demon- stration Project B-2, B-3 Air Products and Chemicals, Inc. B-4, B-5 Air Products Liquid Phase Conversion Company, L.P. ES-18, ES-23, 2-7, 4-9, 4-12, 5-16, 5-17, 5-132, 5-133, B-5, C-4, C-8, D-6 AirPol, Inc. ES-11, ES-22, 2-7, 3-8, 4-2, 4-4, 5-15, 5-17, 5-20, 5-23, B-3, B-5, C-3, C-8, C-9, D-1 Alaska Industrial Development and Export Authority ES-16, ES-23, 2-7, 4-10, 5-16, 5-17, 5-126, B-3, C-5, C-8, D-6, E-1 Appalachian IGCC Demonstration Project, The B-2 Appalachian Power Company B-3, B-5 Arthur D. Little, Inc. ES-23, 2-8, 5-16, 5-17, 5-128, B-4, B-5, C-4, C-8, C-9, D-6, E-1 Arvah B. Hopkins Circulating Fluidized-Bed Repow- ering Project B-3 B Babcock & Wilcox Company, The ES-8, ES-9, ES-11, ES-12, ES-22, ES-24, 2-7, 3-8, 4-3, 4-5, 4-6, 4-7, 4-13, 5-15, 5-17, 5-46, 5-50, 5-78, 5-86, B-1, B-2, B-3, B-4, B-5, C-3, C-4, C-7, C-8, C-9, D-2, D-4, E-1 Bechtel Corporation ES-7, ES-11, ES-22, 2-8, 4-2, 4-4, 5-15, 5-17, 5-24, B-3, B-5, C-3, C-8, D-1 Bechtel Development Company B-2 Bethlehem Steel Corporation ES-2, ES-19, ES-23, 2-8, 4-11, 4-12, 5-16, 5-17, 5-152, B-2, B-3, B-5, C-3, C-4, C-8, D-7 Blast Furnace Granular-Coal Injection System Demonstration Project ES-2, ES-19, ES-23, 2-8, 4-12, 5-13, 5-16, 5-17, 5-152, B-3, C-4, C-8, D-7 C Calvert City Advanced Energy Project B-4 Camden Clean Energy Demonstration Project B-4 Cement Kiln Flue Gas Recovery Scrubber ES-19, ES-23, 2-7, 4-12, 5-13, 5-16, 5-18, 5-160, B-2, B-4, C-4, C-7, D-8 Centerior Energy Corporation B-4 Clean Coal Combined-Cycle Project B-4 Clean Coal Diesel Demonstration Project ES-23, 2-8, 4-8, 5-9, 5-16, 5-17, 5-128, B-4, B-5, C-4, C-8, C-9, D-6 Clean Energy IGCC Demonstration Project B-2, B-3, B-5, D-5 Clean Energy Partners Limited Partnership B-5 Clean Power Cogeneration Limited Partnership B-3 Clean Power from Integrated Coal/Ore Reduction (CPICOR™) ES-23, 2-8, 5-13, 5-16, 5-17, 5-148, B-4, B-6, C-5, C-8, C-9, D-7 Coal Diesel Combined-Cycle Project B-5 Coal Tech Corporation ES-19, ES-23, 2-7, 4-11, 4-12, 5-16, 5-17, 5-156, B-1, B-4, C-3, C-7, D-8 Coal Waste Recovery Advanced Technology Demonstration B-2 Colorado-Ute Electric Association, Inc. B-2 Combustion Engineering IGCC Repowering Project B-3, B-5, C-4 Program Update 1999 Index-1 Combustion Engineering, Inc. B-2 Commercial Demonstration of the NOXSO SO,/NO, Removal Flue Gas Cleanup System ES-2, ES-22, 2-8, 2-13, 4-1, 5-6, 5-15, 5-18, 5-72, B-3, B-5, C-4, C-8, D-4 Commercial-Scale Demonstration of the Liquid Phase Methanol (LPMEOH™) ES-18, ES-23, 2-7, 4-12, 5-10, 5-11, 5-16, 5-17, 5-132, B-4, B-5, C-4, C-8, D-6 Confined Zone Dispersion Flue Gas Desulfurization ES-7, ES-11, ES-22, 2-8, 4-4, 5-3, 5-15, 5-17, 5-24, B-3, B-5, C-3, C-8, D-1 Cordero Coal-Upgrading Demonstration Project B-4 Cordero Mining Company B-4 COREX Ironmaking Demonstration Project B-2 CPICOR™ Management Company L.L.C. ES-23, 2-8, 4-11, 5-12, 5-16, 5-17, 5-148, B-3, B-4, B-6, C-5, C-8, C-9, D-7 CQInc. ES-17, ES-18, ES-23, ES-24, 2-7, 3-8, 4-9, 4-12, 4-13, 5-10, 5-16, 5-17, 5-138, B-2, B-3, B-6, C-3, C-7, D-7 Custom Coals International ES-2, ES-23, 2-8, 2-13, 3-1, 4-1, 5-10, 5-16, 5-17, 5-134, B-4, C-4, C-8, D-7 D Dairyland Power Cooperative B-3 Demonstration of Advanced Combustion Techniques for a Wall-Fired Boiler ES-8, ES-12, ES-22, 2-7, 4-5, 5-5, 5-15, 5-18, 5-42, B-2, B-6, C-3, C-7, C-9, D-3 Demonstration of Coal Diesel Technology at Easton Utilities B-4 Index-2 Program Update 1999 Demonstration of Coal Reburning for Cyclone Boiler NO, Control ES-8, ES-11, ES-22, 2-7, 4-5, 5-5, 5-15, 5-17, 5-46, B-3, B-4, C-4, C-7, C-9, D-2 Demonstration of Innovative Applications of Tech- nology for the CT-121 FGD__ES-7, ES-11, ES-22, ES-24, 2-7, 4-4, 4-13, 5-3, 5-15, 5-18, 5-36, B-3, B-6, C-4, C-7, C-9, D-2 Demonstration of Selective Catalytic Reduction Technology for the Control of NO, Emissions from High-Sulfur, Coal-Fired Boilers ES-8, ES-11, ES-22, 2-7, 4-5, 5-5, 5-15, 5-18, 5-62, B-3, B-6, C-3, C-7, D-3 Demonstration of the Union Carbide CANSOLVT System at the Alcoa Generating Corporation Warrick Power Plant B-4 Development of the Coal Quality Expert™ ES-17, ES-18, ES-23, ES-24, 2-7, 3-8, 4-12, 4-13, 5-11, 5-16, 5-17, 5-138, B-2, B-3, B-6, C-3, C-7, D-7 Direct Iron Ore Reduction to Replace Coke Oven/ Blast Furnace for Steelmaking —B-2 DMEC-|! Limited Partnership B-3, B-6 Duke Energy Corp. B-4, B-5 E Eastman Kodak Company — B-5 ENCOAL Corporation ES-17, ES-18, ES-23, 2- 8, 4-9, 4-12, 5-16, 5-17, 5-142, B-3, B-6, C- 4, C-8, C-9, D-7 ENCOAL* Mild Coal Gasification Project ES-17, ES-18, ES-23, 2-8, 4-12, 5-10, 5-11, 5-16, 5-17, 5-142, B-3, B-6, C-4, C-8, C-9, D-7 Energy and Environmental Research Corporation ES-8, ES-9, ES-11, ES-12, ES-22, ES-24, 2-7, 2-8, 4-3, 4-5, 4-6, 4-7, 4-13, 4-26, 5-15, 5-17, 5-54, 5-82, B-2, B-3, B-6, C-3, C-4, C-7, C-8, D-2, D-4, E-1 Energy International, Inc. B-2 Enhancing the Use of Coals by Gas Reburning and Sorbent Injection ES-9, ES-12, ES-22, ES-24, 2-7, 4-7, 5-6, 5-15, 5-17, 5-82, B-2, B-6, C-3, C-4, C-7, D-4 Evaluation of Gas Reburning and Low-NO, Burners ona Wall-Fired Boiler ES-8, ES-11, ES-22, ES-24, 2-8, 4-5, 4-13, 5-5, 5-15, 5-17, 5-54, B-3, B-6, C-3, C-8, D-2 Externally Fired Combined-Cycle Demonstration Project B-6 F B-2, B-3 Four Rivers Energy Modernization Project B-4, B-5 Four Rivers Energy Partners, L.P. B-4, B-5, B-6 Full-Scale Demonstration of Low-NOx Cell Burner Retrofit ES-8, ES-11, ES-22, ES-24, 2-7, 3-8, 4-5, 4-13, 5-5, 5-15, 5-17, 5-50, B-3, B-5, C-3, C-8, D-2 Foster Wheeler Power Systems, Inc. G General Electric Company B-2 H Healy Clean Coal Project ES-2, ES-16, ES-23, 2-7, 2-13, 4-8, 4-10, 5-9, 5-16, 5-17, 5-126, B-3, C-5, C-8, D-6 I Innovative Coke Oven Gas Cleaning System for Retrofit B-2, B-5, C-3, C-4 Integrated Coal Gasification Steam Injection Gas Turbine Demonstration Plants with Hot Gas Cleanup B-2 Integrated Dry NO./SO, Emissions Control System ES-10, ES-13, ES-22, 2-8, 4-7, 5-6, 5-15, 5-18, 5-94, B-3, C-3, C-8, C-9, D-4 J Jacksonville Electric Authority B-6 JEA ES-22, 2-7, 4-6, 5-15, 5-17, 5-104, B-3, B-6, C-5, C-7, C-9, D-5 JEA Large-Scale CFB Combustion Demonstration Project ES-22, 2-7, 5-9, 5-15, 5-17, 5-104, B-3, B-6, C-5, C-7, C-9, D-5 K Kentucky Pioneer Energy IGCC Demonstration Project ES-1, ES-23, 2-8, 4-8, 5-9, 5-16, 5-17, 5-116, B-5, C-5, C-8, C-9 Kentucky Pioneer Energy, L.L.C. ES-23, 2-8, 5-16, 5-17, 5-116, C-5, C-8, C-9, D-5 L Lakeland, City of, Lakeland Electric ES-22, 2-8, 5-15, 5-17, 5-100, 5-102, B-6, C-5, C-8, C-9, D-4, D-5 LIFAC Sorbent Injection Desulfurization Demonstra- tion Project ES-7, ES-11, ES-22, 2-8, 4-4, 5-3, 5-15, 5-17, 5-28, B-3, B-6, C-3, C-8, D-1 LIFAC-North America ES-7, ES-11, ES-22, 2-8, 4-2, 4-4, 5-15, 5-17, 5-28, B-3, B-6, C-3, C-8, D-1 LIMB Demonstration Project Extension and Coolside Demonstration ES-9, ES-12, ES-22, 2-7, 4-7, 5-6, 5-15, 5-17, 5-86, B-1, B-4, C-3, C-7, D-3 LNS Burner for Cyclone-Fired Boilers Demonstra- tion Project B-3 M M.W. Kellogg Company, The B-2 McDermott Technology, Inc. ES-9, ES-12, ES-22, 2-7, 4-7, 5-15, 5-17, 5-86, B-1, B-4, C-3, C-7, D-3 McIntosh Unit 4A PCFB Demonstration Project ES-22, 2-8, 4-8, 5-9, 5-15, 5-17, 5-100, 5-102, B-6, C-5, C-8, D-4 McIntosh Unit 4B Topped PCFB Demonstration Project ES-22, 2-8, 4-8, 5-9, 5-15, 5-17, 5-100, 5-102, B-4, B-6, C-5, C-8, C-9, D-5 Micronized Coal Reburning Demonstration for NO, Control ES-2, ES-8, ES-11, ES-22, 2-8, 4-5, 5-5, 5-15, 5-17, 5-58, B-4, B-5, B-6, C-8, D-2 Milliken Clean Coal Technology Demonstration Project ES-9, ES-12, ES-13, ES-22, 2-8, 4-7, 5-6, 5-15, 5-18, 5-90, B-4, B-6, C-4, C-8, C-9, D-3 Milliken Station B-5 Minnesota Department of Natural Resources B-2 MK-Ferguson Company B-3 N New York State Electric & Gas Corporation ES-8, ES-9, ES-11, ES-12, ES-13, ES-22, 2-8, 4-3, 4-5, 4-7, 5-15, 5-17, 5-18, 5-58, 5-90, B-4, B-5, B-6, C-4, C-8, C-9, D-2, D-3, E-3 Nichols CFB Repowering Project B-3 NOXSO Corporation ES-2, ES-22, 2-8, 2-13, 3-1, 4-1, 4-6, 5-15, 5-18, 5-72, B-3, B-5, C-4, C-8, D-4 Nucla CFB Demonstration Project ES-15, ES-16, ES-23, 2-7, 3-8, 4-10, 5-9, 5-16, 5-18, 5-110, B-2, B-4, C-3, C-7, D-S O Ohio Power Company, The ES-15, ES-16, ES-23, ES-24, 2-7, 4-6, 4-10, 4-13, 5-16, 5-18, 5-106, B-1, B-5, C-3, C-7, C-9, D-5 B-2, B-3 Otisca Fuel Demonstration Project B-3 Otisca Industries, Ltd. B-3 Ohio Ontario Clean Fuels, Inc. P Passamaquoddy Tribe ES-19, ES-23, 2-7, 4-11, 4-12, 5-16, 5-18, 5-160, B-2, B-4, C-4, C-7, D-8 Pennsylvania Electric Company B-4, B-5, B-6, C-4 PFBC Utility Demonstration Project B-3, B-5 Pifion Pine IGCC Power Project ES-23, 2-8, 2-13, 4-8, 4-10, 5-9, 5-16, 5-18, 5-118, B-4, C-5, C-8, C-9, D-5 Postcombustion Sorbent Injection Demonstration Project B-2 Program Update 1999 Index-3 Prototype Commercial Coal/Oil Coprocessing Project B-2, B-3 PSI Energy 4-8 Public Service Company of Colorado ES-10, ES-13, ES-22, 2-8, 4-3, 4-7, 5-15, 5-18, 5-94, B-3, C-3, C-8, C-9, D-4 Pulse Combustor Design Qualification Test ES-23, 2-8, 2-13, 5-13, 5-16, 5-18, 5-150, B-4, B-6, C-8, D-8 Pure Air on the Lake, L.P. ES-7, ES-11, ES-22, ES-24, 2-7, 3-8, 4-2, 4-3, 4-4, 4-13, 5-15, 5-18, 5-32, B-2, B-5, C-4, C-7, C-9, D-2 R Rosebud SynCoal Partnership B-2, B-3 S Self-Scrubbing Coal™: An Integrated Approach to Clean Air ES-2, ES-23, 2-8, 2-13, 4-1, 5-11, 5-16, 5-17, 5-134, B-4, C-4, C-8, D-7 Sierra Pacific Power Company ES-23, 2-8, 4-8, 4-10, 5-16, 5-18, 5-118, B-4, C-5, C-8, C-9, D-5 SNOX™ Flue Gas Cleaning Demonstration Project ES-9, ES-12, ES-22, 2-7, 4-7, 5-6, 5-15, 5-17, 5-74, B-2, B-6, C-3, C-7, C-9, D-3 Southern Company Services, Inc. ES-7, ES-8, ES-11, ES-12, ES-22, ES-24, 2-7, 4-2, 4-3, 4-4, 4-5, 4-13, 5-15, 5-18, 5-36, 5-42, 5-62, 5-66, B-2, B-3, B-5, B-6, C-3, C-4, C-7, C-9, D-2, D-3, E-3 Southwestern Public Service Company B-3 Index-4 Program Update 1999 SOx-NOx-Rox Box™ Flue Gas Cleanup Demonstra- tion Project ES-9, ES-12, ES-22, 2-7, 4-7, 5-6, 5-15, 5-17, 5-78, B-2, B-5, C-3, C-7, C-9, D-4 T Tallahassee, City of B-2, B-3, B-4, B-6 TAMCO Power Partners B-4, B-5 Tampa Electric Company ES-1, ES-16, ES-23, ES-24, 2-8, 4-10, 4-13, 5-16, 5-18, 5-120, B-3, C-5, C-8, C-9 Tampa Electric Integrated Gasification Combined- Cycle Project ES-1, ES-16, ES-23, ES-24, 2-8, 4-8, 4-10, 4-13, 5-9, 5-16, 5-18, 5-120, B-3, C-5, C-8, C-9, D-6 Tennessee Valley Authority B-4, B-5 ThermoChem, Inc. ES-23, 2-8, 5-12, 5-16, 5-18, 5-150, B-4, B-6, C-8, D-8 Tidd PFBC Demonstration Project ES-1, ES-15, ES-16, ES-23, ES-24, 2-7, 4-10, 4-13, 5-9, 5-16, 5-18, 5-106, B-1, B-5, C-3, C-7, C-9, D-5 Toms Creek IGCC Demonstration Project B-4, B-5 TransAlta Resources Investment Corporation B-3 Tri-State Generation and Transmission Association ES-15, ES-16, ES-23, 2-7, 3-8, 4-6, 4-10, 5-16, 5-18, 5-110, B-4, C-3, C-7, D-5 TRW, Inc. B-2, B-3 U Underground Coal Gasification Demonstration Project B-2 Union Carbide Chemicals and Plastics Company Inc. B-4 United Coal Company B-2 WwW Wabash River Coal Gasification Repowering Joint Venture ES-16, ES-23, ES-24, 2-8, 4-10, 4-13, 5-16, 5-18, 5-122, B-4, C-8, C-9, D-6 Wabash River Coal Gasification Repowering Project ES-16, ES-23, ES-24, 2-8, 4-8, 4-10, 4-13, 5-9, 5-16, 5-18, 5-122, B-4, C-4, C-8, C-9, D-6 Warren Station Externally Fired Combined-Cycle Demonstration B-4, B-5, C-4 Weirton Steel Corporation B-2 Western Energy Company B-2, B-3 Western SynCoal LLC _ES-18, ES-23, 2-7, 4-9, 4-12, 5-10, 5-11, 5-16, 5-18, 5-136, B-2, B-3, C-4, C-7, D-7 Y York County Energy Partners Cogeneration Project B-4, B-6 York County Energy Partners, L.P. B-4 wx U.S. GOVERNMENT PRINTING OFFICE: 2000 460-787/00173 AAT TATAAAATAATATAAA AAT Contents Executive Summary Section 1: Role of the CCT Program Section 2: Program Implementation Section 3: Funding and Costs Section 4: CCT Program Accomplishments Section 5: CCT Projects SO, Control Technologies Fact Sheets NO, Control Technologies Fact Sheets Combined SO,/NO, Control Technologies Fact Sheet Fluidized-Bed Combustion Fact Sheets Integrated Gasification Combined-Cycle Fact Sheets Advanced Combustion/Heat Engines Fact Sheets Coal Processing for Clean Fuels Fact Sheets Industrial Applications Fact Sheets Appendix A: Historical Perspective and Legislative History Appendix B: Program History Appendix C: Environmental Aspects Appendix D: CCT Project Contacts Appendix E: Acronyms, Abbreviations, and Symbols Index